EXHIBIT 1
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                                     COMPTON
                              ---------------------
                              PETROLEUM CORPORATION



                             ANNUAL INFORMATION FORM
                      FOR THE YEAR ENDED DECEMBER 31, 2003

                          COMPTON PETROLEUM CORPORATION





                                  May 14, 2004


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                                TABLE OF CONTENTS

                                                                            PAGE

ABBREVIATIONS AND CONVERSION FACTORS...........................................2

NOTES AND DEFINITIONS..........................................................3

FORWARD-LOOKING STATEMENTS.....................................................7

CORPORATE STRUCTURE............................................................8

GENERAL DEVELOPMENT OF THE BUSINESS............................................8

DESCRIPTION OF THE BUSINESS....................................................9

STATEMENT OF RESERVES DATA....................................................14

PRICING ASSUMPTIONS...........................................................18

ADDITIONAL INFORMATION RELATING TO RESERVES DATA..............................20

DIVIDENDS.....................................................................25

CAPITAL STRUCTURE.............................................................25

MARKET FOR SECURITIES.........................................................27

CONFLICTS OF INTEREST.........................................................27

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS...................27

INTERESTS OF EXPERTS..........................................................28

RATINGS ......................................................................28

DIRECTORS AND OFFICERS........................................................28

AUDIT, FINANCE AND RISK COMMITTEE INFORMATION.................................30

COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE..............................30

EXTERNAL AUDITOR FEES.........................................................31

TRANSFER AGENT AND REGISTRAR..................................................31

RISK FACTORS..................................................................31

ADDITIONAL INFORMATION........................................................32

SCHEDULE A....................................................................34

SCHEDULE B....................................................................36

SCHEDULE C....................................................................38


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                      ABBREVIATIONS AND CONVERSION FACTORS



ABBREVIATIONS

The following are abbreviations of technical term used throughout this annual
information form:

"BBL" means barrel; "BBLS" means barrels;

"BCF" means billion cubic feet;

"BOE" means barrels of crude oil equivalent;

"BOEPD" or "BOE/D" 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;

"MCFE" means thousand cubic feet equivalent ;

"MMCFD" or "MMCF/D" means million cubic feet per day;

"MSTB" means thousand stock tank barrels; and

"NGLS" means natural gas liquids.


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CONVERSION FACTORS


To conform with common usage, Standard Imperial Units of measurement are used in
this Annual Information Form to describe exploration and production activities.
The following table sets forth conversions between Standard Imperial Units and
the International System of Units (or metric units).

--------------------------------------------------------------------------------
     TO CONVERT FROM                 TO                 MULTIPLY BY
--------------------------------------------------------------------------------
mcf                             Cubic metres                0.028174
boe                             mcfe                        6
Cubic metres of gas             Cubic feet                 35.31
bbls                            Cubic metres                0.159
Cubic metres of oil             Bbls                        6.289
Feet                            Metres                      0.305
Metres                          Feet                        3.281
Miles                           Kilometres                  1.609
Kilometres                      Miles                       0.621
ACRES                           HECTARES                    0.405
Hectares                        Acres                       2.471
--------------------------------------------------------------------------------


                              NOTES AND DEFINITIONS


The determination of oil and natural gas reserves involves the preparation of
estimates that have an inherent degree of associated uncertainty. Categories of
proved, probable and possible reserves have been established to reflect the
level of these uncertainties and to provide an indication of the probability of
recovery.

The estimation and classification of reserves requires the application of
professional judgment combined with geological and engineering knowledge to
assess whether or not specific reserves classification criteria have been
satisfied. Knowledge of concepts including uncertainty and risk, probability and
statistics, and deterministic and probabilistic estimation methods is required
to properly use and apply reserves definitions.

"RESERVES" are estimated remaining quantities of oil and natural gas and related
substances anticipated to be recoverable from known accumulations, from a given
date forward, based on (a) analysis of drilling, geological, geophysical, and
engineering data; (b) the use of established technology; and (c) specified
economic conditions, which are generally accepted as being reasonable and shall
be disclosed. Reserves are classified according to the degree of certainty
associated with the estimates.

"PROVED" reserves are those reserves that can be estimated with a high degree of
certainty to be recoverable. It is likely that the actual remaining quantities
recovered will exceed the estimated proved reserves. Nine out of ten times,
proved reserves are likely to increase.

"DEVELOPED PRODUCING" reserves are those reserves that are expected to be
recovered from completion intervals open at the time of the estimate. These
reserves may be currently producing or, if shut-in, they must have previously
been on production, and the date of resumption of production must be known with
reasonable certainty.

"DEVELOPED NON-PRODUCING" reserves are those reserves that either have not been
on production, or have previously been on production, but are shut-in, and the
date of resumption of production is unknown.

"UNDEVELOPED" reserves are those reserves expected to be recovered from known
accumulations where a significant expenditure (e.g., when compared to the cost
of drilling a well) is required to render them capable of production. They must
fully meet the requirements of the reserves classification (proved, probable,
possible) to which they are assigned.


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In multi-well pools, it may be appropriate to allocate total pool reserves
between the developed and undeveloped categories or to sub-divide the developed
reserves for the pool between developed producing and developed non-producing.
This allocation should be based on the estimator's assessment as to the reserves
that will be recovered from specific wells, facilities and completion intervals
in the pool and their respective development and production status.

"PROBABLE" reserves are those additional reserves that are less certain to be
recovered than proved reserves. It is equally likely that the actual remaining
quantities recovered will be greater or less than the sum of the estimated
proved plus probable reserves.

The following terms, when used in this document, have the following meanings, as
set forth in National Instrument 51-101:

"ASSOCIATED GAS" means the gas cap overlying a crude oil accumulation in a
reservoir.

"CONSTANT PRICES AND COSTS" means prices and costs used in an estimate that are:

         (a)      the Company's prices and costs as at the effective date of the
                  estimation, held constant throughout the estimated lives of
                  the properties to which the estimate applies;

         (b)      if, and only to the extent that, there are fixed or presently
                  determinable future prices or costs to which the Company is
                  legally bound by a contractual or other obligation to supply a
                  physical product, including those for an extension period of a
                  contract that is likely to be extended, those prices or costs
                  rather than the prices and costs referred to in paragraph (a).

For the purpose of paragraph (a), the reporting issuer's prices will be the
posted price for oil and the spot price for gas, after historical adjustments
for transportation, gravity and other factors.

"COMPANY" or "COMPTON" means Compton Petroleum Corporation.

"CRUDE OIL" or "OIL" means a mixture that consists mainly of pentanes and
heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon
compounds, that is recoverable at a well from an underground reservoir and that
is liquid at the conditions under which its volume is measured or estimated. It
does not include solution gas or natural gas liquids.

"DEVELOPMENT COSTS" means costs incurred to obtain access to reserves and to
provide facilities for extracting, treating, gathering and storing the oil and
gas from the reserves. More specifically, development costs, including
applicable operating costs of support equipment and facilities and other costs
of development activities, are costs incurred to:

         (a)      gain access to and prepare well locations for drilling,
                  including surveying well locations for the purpose of
                  determining specific development drilling sites, clearing
                  ground, draining, road building, and relocating public roads,
                  gas lines and power lines, to the extent necessary in
                  developing the reserves;

         (b)      drill and equip development wells, development type
                  stratigraphic test wells and service wells, including the
                  costs of platforms and of well equipment such as casing,
                  tubing, pumping equipment and the wellhead assembly;

         (c)      acquire, construct and install production facilities such as
                  flow lines, separators, treaters, heaters, manifolds,
                  measuring devices and production storage tanks, natural gas
                  cycling and processing plants, and central utility and waste
                  disposal systems; and

         (d)      provide improved recovery systems.


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"DEVELOPMENT WELL" means a well drilled inside the established limits of an oil
or gas reservoir, or in close proximity to the edge of the reservoir, to the
depth of a stratigraphic horizon known to be productive.

"EXPLORATION COSTS" means costs incurred in identifying areas that may warrant
examination and in examining specific areas that are considered to have
prospects that may contain oil and gas reserves, including costs of drilling
exploratory wells and exploratory type stratigraphic test wells. Exploration
costs may be incurred both before acquiring the related property (sometimes
referred to in part as "prospecting costs") and after acquiring the property.
Exploration costs, which include applicable operating costs of support equipment
and facilities and other costs of exploration activities, are:

         (a)      costs of topographical, geochemical, geological and
                  geophysical studies, rights of access to properties to conduct
                  those studies, and salaries and other expenses of geologists,
                  geophysical crews and others conducting those studies
                  (collectively sometimes referred to as "geological and
                  geophysical costs");

         (b)      costs of carrying and retaining unproved properties, such as
                  delay rentals, taxes (other than income and capital taxes) on
                  properties, legal costs for title defence, and the maintenance
                  of land and lease records;

         (c)      dry hole contributions and bottom hole contributions;

         (d)      costs of drilling and equipping exploratory wells; and

         (e)      costs of drilling exploratory type stratigraphic test wells.

"EXPLORATORY WELL" means a well that is not a development well, a service well
or a stratigraphic test well.

"FIELD" means an area consisting of a single reservoir or multiple reservoirs
all grouped on or related to the same individual geological structural feature
and/or stratigraphic condition. There may be two or more reservoirs in a field
that are separated vertically by intervening impervious strata or laterally by
local geologic barriers, or both. Reservoirs that are associated by being in
overlapping or adjacent fields may be treated as a single or common operational
field. The geological terms "structural feature" and "stratigraphic condition"
are intended to denote localized geological features, in contrast to broader
terms such as "basin", "trend", "province", "play" or "area of interest".

"FUTURE PRICES AND COSTS" means future prices and costs that are:

         (a)      generally accepted as being a reasonable outlook of the
                  future;

         (b)      if, and only to the extent that, there are fixed or presently
                  determinable future prices or costs to which the Company is
                  legally bound by a contractual or other obligation to supply a
                  physical product, including those for an extension period of a
                  contract that is likely to be extended, those prices or costs
                  rather than the prices and costs referred to in paragraph (a).

"FUTURE INCOME TAX EXPENSES" means future income tax expenses estimated
(generally, year-by-year):

         (a)      making appropriate allocations of estimated unclaimed costs
                  and losses carried forward for tax purposes, between oil and
                  gas activities and other business activities;

         (b)      without deducting estimated future costs (for example, Crown
                  royalties) that are not deductible in computing taxable
                  income;

         (c)      taking into account estimated tax credits and allowances (for
                  example, royalty tax credits); and

         (d)      applying to the future pre-tax net cash flows relating to the
                  Company's oil and gas activities the appropriate year-end
                  statutory tax rates, taking into account future tax rates
                  already legislated.


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"FUTURE NET REVENUE" means the estimated net amount to be received with respect
to the development and production of reserves (including synthetic oil, coal bed
methane and other non-conventional reserves) estimated using constant prices and
costs or forecast prices and costs.

"GROSS" means:

         (a)      in relation to the Company's interest in production or
                  reserves, its "company gross reserves", which are it's working
                  interest (operating or non-operating) share before deduction
                  of royalties and without including any royalty interests of
                  the Company;

         (b)      in relation to wells, the total number of wells in which the
                  Company has an interest; and

         (c)      in relation to properties, the total area of properties in
                  which the Company has an interest.

"NATURAL GAS" means the lighter hydrocarbons and associated non-hydrocarbon
substances occurring naturally in an underground reservoir, which under
atmospheric conditions are essentially gases but which may contain natural gas
liquids. Natural gas can exist in a reservoir either dissolved in crude oil
(solution gas) or in a gaseous phase (associated gas or non-associated gas).
Non-hydrocarbon substances may include hydrogen sulphide, carbon dioxide and
nitrogen.

"NATURAL GAS LIQUIDS" means those hydrocarbon components that can be recovered
from natural gas as liquids including, but not limited to, ethane, propane,
butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.

"NET" means:

         (a)      in relation to the Company's interest in production or
                  reserves its working interest (operating or non-operating)
                  share after deduction of royalty obligations, plus its royalty
                  interests in production or reserves;

         (b)      in relation to the Company's interest in wells, the number of
                  wells obtained by aggregating the Company's working interest
                  in each of its gross wells; and

         (c)      in relation to the Company's interest in a property, the total
                  area in which the Company has an interest multiplied by the
                  working interest owned by the Company.

"NON-ASSOCIATED GAS" means an accumulation of natural gas in a reservoir where
there is no crude oil.

"OPERATING COSTS" or "PRODUCTION COSTS" means costs incurred to operate and
maintain wells and related equipment and facilities, including applicable
operating costs of support equipment and facilities and other costs of operating
and maintaining those wells and related equipment and facilities.

"PRODUCTION" means recovering, gathering, treating, field or plant processing
(for example, processing gas to extract natural gas liquids) and field storage
of oil and gas.

"PROPERTY" includes:

         (a)      fee ownership or a lease, concession, agreement, permit,
                  licence or other interest representing the right to extract
                  oil or gas subject to such terms as may be imposed by the
                  conveyance of that interest;

         (b)      royalty interests, production payments payable in oil or gas,
                  and other non-operating interests in properties operated by
                  others; and


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         (c)      an agreement with a foreign government or authority under
                  which a reporting issuer participates in the operation of
                  properties or otherwise serves as "producer" of the underlying
                  reserves (in contrast to being an independent purchaser,
                  broker, dealer or importer). A property does not include
                  supply agreements, or contracts that represent a right to
                  purchase, rather than extract, oil or gas.

"PROPERTY ACQUISITION COSTS" means costs incurred to acquire a property
(directly by purchase or lease, or indirectly by acquiring another corporate
entity with an interest in the property), including:

         (a)      costs of lease bonuses and options to purchase or lease a
                  property;

         (b)      the portion of the costs applicable to hydrocarbons when land
                  including rights to hydrocarbons is purchased in fee;

         (c)      brokers' fees, recording and registration fees, legal costs
                  and other costs incurred in acquiring properties.

"PROVED PROPERTY" means a property or part of a property to which reserves have
been specifically attributed.

"RESERVOIR" means a porous and permeable underground formation containing a
natural accumulation of producible oil or gas that is confined by impermeable
rock or water barriers and is individual and separate from other reservoirs.

"SERVICE WELL" means a well drilled or completed for the purpose of supporting
production in an existing field. Wells in this class are drilled for the
following specific purposes: gas injection (natural gas, propane, butane or flue
gas), water injection, steam injection, air injection, salt-water disposal,
water supply for injection, observation, or injection for combustion.

"SHUT IN WELL" means a well which is capable of economic production or which the
Company considers capable of production but which for a variety of reasons,
including, but not limited to, lack of markets or development, is not placed on
production at the present time.

"SOLUTION GAS" means natural gas dissolved in crude oil.

"STRATIGRAPHIC TEST WELL" means a drilling effort, geologically directed, to
obtain information pertaining to a specific geologic condition. Ordinarily, such
wells are drilled without the intention of being completed for hydrocarbon
production. They include wells for the purpose of core tests and all types of
expendable holes related to hydrocarbon exploration. Stratigraphic test wells
are classified as (a) "exploratory type" if not drilled into a proved property;
or (b) "development type", if drilled into a proved property. Development type
stratigraphic wells are also referred to as "evaluation wells".

"SUPPORT EQUIPMENT AND FACILITIES" means equipment and facilities used in oil
and gas activities, including seismic equipment, drilling equipment,
construction and grading equipment, vehicles, repair shops, warehouses, supply
points, camps, and division, district or field offices.

"UNPROVED PROPERTY" means a property or part of a property to which no reserves
have been specifically attributed.

"WELL ABANDONMENT COSTS" means costs of abandoning a well (net of salvage value)
and of disconnecting the well from the surface gathering system. They do not
include costs of abandoning the gathering system or reclaiming the wellsite.


                           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 believes that the


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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'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 Company'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 Company's name to
Compton Petroleum Corporation and the Company 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 Company'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.

Effective May 2, 2003, MPP Ltd. ("MPP LTD."), a wholly-owned subsidiary of the
Company, was formed under the laws of Alberta. On June 16, 2003, MPP Ltd., as
general partner, and 1051940 Alberta Ltd., as limited partner, formed a limited
partnership called the Mazeppa Processing Partnership. Mazeppa Processing
Partnership owns, among other assets, the Mazeppa and Gladys gas plants.


                       GENERAL DEVELOPMENT OF THE BUSINESS

Compton is an Alberta based independent public company actively engaged in the
exploration, development and production of natural gas, ngls and crude oil in
the Western Canadian Sedimentary Basin (the "WCSB") in Canada. The Company'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 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

Compton focused on the exploration and development of internally generated
prospects in 2001. The Company drilled 95 gross wells with an overall success
rate of 76% in 2001. This drilling focus was complemented by 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 Company as it


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enabled Compton to consolidate working interests and obtain operatorship of key
properties within its core area of Southern Alberta.

In 2002, Compton again focused on the continued exploration and development of
its internally generated prospects. The Company's $155 million capital program
included the drilling of 87 gross wells with a success rate of 90%. Compton's
total established reserves increased 19.8 mmboe from 83.7 mmboe to 103.5 mmboe
during 2002.

During 2002, the Company acquired a 50% working interest and operatorship of a
30 mmcfd natural gas plant, 95 sections of contiguous undeveloped lands and
1,911 mboe of established, deep tight natural gas reserves at Callum. 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. Both Niton and Callum are now
core areas for Compton.

In 2003, Compton focused on the resolution of pipeline and facility constraints
in its Southern Alberta core area. The Mazeppa Processing Partnership purchased
the Mazeppa and Gladys natural gas plants with related compression facilities
and pipelines in Southern Alberta. The partnership is managed and controlled by
Compton and provided Compton flexibility to pursue and accelerate various
processing alternatives, including plant expansions. The sour capacity of the
Mazeppa plant was expanded by 10 mmcf/d to 90 mmcf/d in 2003 and a 45 mmcf/d
sweet expansion was completed in 2004. The Hooker pipeline system was expanded
to 80 mmcf/d and natural gas production from Brant was offloaded to the ATCO
sales pipeline. With processing restrictions removed, Compton will continue to
aggressively explore lands adjacent to the Mazeppa, Gladys and Brant pipeline
and plant infrastructures.

The Company continued to pursue the exploration and development of its assets
and prospects. The Company's 2003 capital program totaled approximately $285
million, including the consolidation of the Mazeppa gas plant. The Company
drilled 168 wells in 2003 with an 83% success rate.


                           DESCRIPTION OF THE BUSINESS

EXPLORATION AND PRODUCTION OPERATIONS

Compton's exploration, development and exploitation activities are concentrated
principally in three core areas: Southern Alberta in the Centron, Gladys,
Okotoks-Mazeppa, Brant, Hooker, Aphrodite and Callum areas, Central Alberta in
the Bigoray, Niton, Thornbury and Rosevear areas and the Peace River Arch area
in the Cecil-Worsley and Howard areas. These areas are the 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.

PROCESSING OPERATIONS

In June of 2003, Mazeppa Processing Partnership ("MPP") acquired certain
midstream assets from an independent third party. The assets consist of major
natural gas gathering and processing facilities in southern Alberta. The Company
has minimal ownership in MPP; however, the Company manages the activities of MPP
through MPP Ltd., a wholly owned subsidiary, that is the General Partner of MPP.
The Company also processes a significant portion of its production in Southern
Alberta through the facilities and is considered to be a primary beneficiary of
MPP's operations.

The operations of MPP are considered to be a business segment separate and
distinct from the Company's exploration, exploitation, development and
production activities for financial reporting purposes as defined under the
United States Financial Accounting Standards Board interpretation Number 46R
"Consolidation of Variable Interest Entities", and interpretation of "Accounting
Research Bulletin No. 51". The results of the midstream activities are
immaterial to Compton's consolidated financial condition.


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EMPLOYEES


As at December 31, 2003, Compton had 103 full-time employees in its Calgary
office and 26 full-time employees at field locations. MPP had 32 full time
employees at December 31, 2003 at the Mazeppa gas plant.

BUSINESS PLAN AND OPERATING STRATEGY


The Company'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 Company is implementing
this objective by focusing on the efficient exploration, development and
exploitation of 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 Company's operating strategy includes the components set forth below.

CONCENTRATE ON CORE GEOGRAPHIC AREAS. The Company has established and is
expanding its core areas within the WCSB. This geographic core area focus
provides Compton with a balanced portfolio of exploitation, 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 Company with the
opportunity for high working interests, enabling Compton to control the timing
of capital expenditures and facilitates the efficient management of its
activities. Compton's intention is to generate exploration opportunities and to
significantly increase its undeveloped land base within the WCSB in this manner.

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 Company plans to continue to focus on finding and
developing long-life natural gas reserves.

PURSUE FULL-CYCLE EXPLORATION COMPLEMENTED BY SELECTIVE ACQUISITIONS. The
Company plans to continue to reinvest internally-generated cash flow to fund the
growth of its exploration and development program and to further increase
Compton's undeveloped land base to maintain a growing inventory of drilling
prospects in its core geographic areas. The Company 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 Company may defer
exploration projects and enhance its operations and prospects through strategic
acquisitions.

CONTROL OF INFRASTRUCTURE AND OPERATORSHIP. The Company 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 75% of its existing production and, as of December 31, 2003, had a
74% average working interest in its undeveloped lands. This position allows the
Company to exercise discretion in determining the timing and methodology of
Compton's ongoing exploitation, exploration and development programs. The
Company 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. As of
December 31, 2003, the Company has assembled a significant portfolio of
undeveloped land and has working interests in 1,042,802 (767,364 net) acres of
undeveloped land. Management believes that Compton's existing portfolio of
undeveloped land is sufficient to produce at least five years of internally
generate exploration and development prospects. Additionally, the Company holds
a quality, complementary seismic database. The Company's rights to a copy of,
and rights to utilize, extensive seismic data bases of approximately 100,700
kilometres of two-dimensional ("2D") seismic and 2,200 square kilometres of
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 Company.


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MAINTAIN FINANCIAL FLEXIBILITY. The Company is committed to maintaining
financial flexibility to allow Compton to pursue its full-cycle exploration
program in periods of low commodity prices. The Company intends to maintain
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

Southern Alberta is Compton's largest core area, prospective for multi-zone
natural gas, including medium depth Belly River, deep tight Basal Quartz and
Wabamun Crossfield natural gas. Additional exploration upside exists in the
Edmonton, Viking and Glauconite zones, as well as the coal bed methane play that
lies immediately north of Compton's Southern Alberta land base. An undeveloped
land base of 480,859 (399,736 net) acres will provide years of internal drilling
opportunities.

Compton drilled 102 (91 net) wells in Southern Alberta in 2003 with an 87%
success rate. In 2004, Southern Alberta will again be the primary focus of the
Company, with plans to drill 112 (99 net) locations with a capital expenditure
budget of $137 million in the area.

HOOKER

The Hooker play targets tight Basal Quartz sandstones at depths ranging from
2,400 to 3,400 metres. Hooker also holds uphole potential in multiple Belly
River sands. The play covers an extensive area of over 150 sections, at working
interests ranging from 50-100%. Current production extends over four townships.
The Hooker trend has the potential to grow to nine townships with a resource
potential of 500 bcf of natural gas reserves net to Compton.

In 2003, Compton focused on continuing to expand the Hooker play into
predominantly 100% owned acreage. The Company drilled a total of eight
exploratory and 11 development wells with a success rate of 74%. The exploration
program extended the trend six miles to the north and three miles to the
southeast and continued to provide invaluable experience and understanding of
these types of tight gas reservoirs.

With the extension of the Hooker pool to the north and southeast, Compton
estimates that only half of the Hooker trend, as it exists on Compton's lands,
has been developed to date. At the current drilling pace, over five years of
future drilling locations exist at Hooker. In 2004, the Company expects to drill
24 wells in the Hooker trend.

APHRODITE

Aphrodite is a geologically analogous extension to the Hooker Basal Quartz
trend. Compton drilled and cased two exploratory wells at Aphrodite in 2003.
Continued exploration activities are ongoing.

CENTRON/GLADYS/BRANT

Located northeast of Hooker, the Centron/Gladys/Brant area offers medium depth
natural gas in stacked, Belly River sandstones averaging 1,200 meters in depth.
In addition to Belly River production, deeper exploration opportunities are
present in the area. Compton's Belly River production currently extends from
Hooker to Centron, over an area of 28 townships with very few down spacing
locations drilled to date. On lands adjacent to Compton's acreage, historically
more than one well per section has been required to adequately drain the Belly
River zone.

An unusually wet spring in 2003 created drilling delays, but Compton
aggressively pursued its medium depth natural gas program in the second half of
the year. Using seismic data and trend mapping, the Company drilled a total of
70 wells with an 89% success rate. This program resulted in the discovery of new
pools six miles south and five miles east of the existing Belly River producing
area. In 2004, Compton will continue its extensive drilling program in the area
with 74 wells planned. Additionally, the Company plans to assess coal bed
methane opportunities at Centron.


                                      -11-
<PAGE>

OKOTOKS/MAZEPPA

The Okotoks Field has historically been associated with the Okotoks Wabamun "B"
Pool, a 1 TCF, deep, tight, sour natural gas pool. Since acquiring producing
assets in the area in 1996, Compton has continued to expand its operations, and
has developed the property into a multi-zone exploration and exploitation play,
with potential for production throughout a 5,000 foot vertical section.
Production from the Wabamun Formation commenced nearly 50 years ago, and the
remaining reserves from this zone will support production from existing
producing wells for at least another 50 years.

In addition to the Wabamun zone, Compton currently produces from several other
uphole formations in the area, including the Mississippian, Basal Quartz, and
Belly River zones. With an extensive and expanding infrastructure in place,
Compton has the advantage of being able to exploit these shallower zones at low
finding and development costs.

CALLUM

Callum is the Company's most southern area of operations with wells averaging
2,800 metres in depth. The play is prospective for thrusted multiple Upper
Cretaceous Belly River sands. In 2003, Compton drilled three wells with a 100%
success rate. The Company holds over 100 sections of undeveloped land at Callum
and plans to continue exploring the Callum area with 5 wells planned in 2004.

CENTRAL ALBERTA

Central Alberta provides Compton with excellent exploration and development
drilling opportunities and allows the Company to adopt an approach similar to
its successful deep basin style Southern Alberta developments. Compton holds
487,331 (253,731 net) acres of land, located approximately 100 km west of
Edmonton.

Drilling in Central Alberta was delayed in the first half of the year due to wet
spring weather. However, by year end the Company had drilled 36 (21 net) wells
with an overall success rate of 86%. In 2004, Compton plans to spend $33 million
in capital expenditures, drilling 35 (32 net) wells in the area.

NITON

The Company entered the Niton area in December 2002 by acquiring 100 sections of
undeveloped land, a 100% working interest in a 5 mmcf/d natural gas plant and
production of 220 boe/d. Compton has expanded its land position throughout 2003
and held 148 net sections in the area at December 31, 2003. Wells in the Niton
area average 2,600 metres in depth, with primary targets in the Gething and Rock
Creek sands. Uphole opportunities are also present in the Bluesky, Viking and
Cardium zones. The Niton area is very promising as its tight sandstones are
similar geologically to the Hooker trend.

In 2003, 14 wells were drilled at Niton with a 93% success rate. Results were
very promising, resulting in the identification of several new drilling
locations. Compton also expanded its 100% owned natural gas plant to 10 mmcf/d
capacity in December 2003. The Niton area is one of increasing focus for the
Company and the exploration program will be expanded to 14 wells in 2004.

THORNBURY

Shallow natural gas drilling at Thornbury targets the McMurray zone at an
average depth of 400 metres. Compton drilled three successful natural gas wells,
two dry holes and one standing well in the first quarter of 2003, and plans to
drill 15 wells at Thornbury in 2004.

BIGORAY

Bigoray is a mature, high quality, light oil producing area that provides cash
flow for Compton to finance exploration in other areas. Production from the
Cardium sandstone has been maintained throughout 2003 as a result


                                      -12-
<PAGE>

of continued success of the waterflood project. In 2004, Compton will continue
to focus on efficient exploitation of reserves in place and plans to re-initiate
an exploration effort with three wells planned.

PEACE RIVER ARCH

The Peace River Arch area, located north of Grand Prairie, contains multi-zone
potential for both exploration and development opportunities. This core area
includes both light oil production at Cecil/Worsley and natural gas exploration
at Clayhurst, Howard and Pouce Coupe. The Company holds 136,713 (93,608 net)
acres of undeveloped land in the area.

In 2003, Compton drilled 30 (22 net) wells in the Peace River Arch with an 66%
success rate. The Company plans to drill 28 (20 net) locations in 2004 with a
capital expenditures budget of $20 million.

CECIL/WORSLEY

Together, the Cecil and Worsley Charlie Lake pools are estimated to hold 187
million barrels of oil-in-place with an expected primary recovery of 5% to 7%.
Waterflooding has the potential to double oil recovery from the Charlie Lake
reservoirs. A pilot waterflood on the centre of the Worsley Charlie Lake pool
commenced in June 2002 to optimize oil recovery. In December 2002, a response to
the waterflood was evident in offsetting wells. The Worsley waterflood project
has continued to show success in 2003 and a second pilot waterflood on the North
end of the pool has been initiated. A full section waterflood project will be
completed at Worsely in 2004.

The 2003 drilling program included 15 wells and extended the Worsely oil pool a
half mile to the north with three successful step outs. As a result, 16
extension and infill wells are planned for Cecil/Worsley in 2004.

HOWARD

Compton holds over one township of prospective lands in the Howard area, with an
average working interest of 80%. The primary target is natural gas in shallow
Dunvegan sandstones at a depth of 450 meters. However, the area also has
potential in the deeper Charlie Lake and Kiskatinaw zones. The Company drilled
seven wells in 2003 and intends to drill seven follow up locations in 2004.

COMPETITIVE CONDITIONS

Cold winter weather and increased demand depleted natural gas storage levels in
the first quarter of 2003. However, strong injections returned North American
storage to historical levels. With the recovery of storage levels, natural gas
prices stabilized in the US$5.00 - $5.50/mcf NYMEX throughout the remainder of
2003. Although the industry entered 2004 with adequate natural gas supplies,
demand will continue to rise due to increased electricity generation. We expect
natural gas prices to average Cdn $5.00 - $5.50/mcf in 2004. However, oil prices
will continue to be volatile in 2004 due to increased world demand and conflicts
in producing countries.

While the demand for natural gas continues to grow, production may be peaking.
Natural gas wells in the WCSB continued a 10 year trend of lower initial
production rates and higher first year decline rates, resulting in an overall
increase of decline rates in the WCSB. In order to maintain current production
levels, producers must increase drilling and pursue unconventional sources of
natural gas. This was illustrated in 2003 with a record number of wells drilled
in Canada, while overall natural gas deliverability remained flat with 2002.

Unconventional sources of natural gas are necessary to offset conventional
natural gas declines and provide the production growth necessary to fulfill
increasing demand. Unconventional sources include coalbed methane, shale gas,
liquefied natural gas and tight gas. Tight gas, which comprises 80% of Compton's
reserves, is expected to be the largest unconventional form of natural gas
production in the future. The Canadian oil and natural gas industry is also
aggressively pursuing coal bed methane potential and the early results show
significant upside. These new resource plays require a large upfront land base,
technical expertise, experience and difficult project economics which puts more
pressure on the industry.


                                      -13-
<PAGE>

Drilling rigs, service rigs, equipment and experienced crews are currently
operating at maximum capacity, which has resulted in escalating drilling costs
and inefficiencies. Strong demand for experienced professionals has caused a
significant increase in salaries and workloads, further adding to inefficiency
in the industry. Land prices continue to spiral upwards and are consuming an
increasing portion of annual budgets and adding considerably to finding,
development and acquisition ("FD&A") costs. Deeper drilling and more complex
plays will also contribute to higher FD&A costs for the industry in general.
Additionally, the increasing complexity and ever changing government rules
regarding license applications, environmental and governance matters is adding
significantly to overall costs, workloads and timing of operations. The end
result is that while commodity prices are strong, the cost, effort and time of
doing business have also risen dramatically.

SEISMIC

The Company 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 Company). These databases include conventional 2-D
seismic covering 100,700 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 Company has rights to use
6,200 kilometres of seismic covering areas in southern Manitoba. These large
seismic databases are utilized by the Company's exploration team in exploration
and acquisition decisions of the Company.


                           STATEMENT OF RESERVES DATA


Compton's interests in its natural gas and crude oil properties as at December
31, 2003, have been evaluated in a report (the "REPORT") as at January 1, 2004,
prepared by the independent international integrated petroleum engineering and
geological firm, Netherland, Sewell & Associates, Inc. ("NETHERLAND SEWELL").
The following summary of the Company's reserves is calculated and reported in
accordance with National Instrument 51-101, "Standards of Disclosure for Oil and
Gas Activities". Assumptions and qualifications relating to costs, prices for
future production and other matters are included below. The Report is based on
data supplied by the Company and on Netherland Sewell's opinions of reasonable
practice in the industry.

All evaluations of future revenue are after the deduction of future income tax
expenses (unless otherwise noted in the tables) royalties, development costs,
production costs and well abandonment costs but before consideration of indirect
costs such as administrative, overhead and other miscellaneous expenses. The
estimated future net revenue contained in the following tables do not
necessarily represent the fair market value of Compton's reserves. There is no
assurance that the forecast price and cost assumptions contained in the
Netherland Sewell Report will be attained and variances could be material. Other
assumptions and qualifications relating to costs and other matters are
summarized in the notes to the following tables. The recovery and reserves
estimates on Compton's properties described herein are estimates only. The
actual reserves on Compton's properties may be greater or less than those
calculated.

This statement is dated May 14, 2004. The information being provided in this
statement has an effective date of December 31, 2003 and a preparation date of
April 5, 2004.


                                      -14-
<PAGE>

CONSTANT PRICE AND COST

The following table provides a summary of the Company's reserves by product
type, based upon constant price and cost assumptions, before and after
applicable royalties, excluding ARTC, at the end of the most recent fiscal year.

SUMMARY OF OIL AND GAS RESERVES USING CONSTANT PRICING AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                                CRUDE OIL              NATURAL GAS                 NGLS(1)
                                             GROSS        NET        GROSS        NET        GROSS        NET
                                             (mbbl)      (mbbl)      (mcf)       (mcf)       (mbbl)      (mbbl)
----------------------------------------------------------------------------------------------------------------
<S>                                           <C>         <C>       <C>         <C>           <C>          <C>
PROVED
Developed Producing                           6,777       6,235     323,832     265,057       6,628        5,059
Developed Non-Producing                         164         159      31,577      23,842         575          375
Undeveloped                                   2,499       1,933      49,130      37,674       1,117          781
----------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                  9,440       8,327     404,539     326,573       8,320        6,215
----------------------------------------------------------------------------------------------------------------

(1)      Ngl volumes include sulphur volumes with a conversion rate of 1 long ton = 1 barrel.
</TABLE>

The table set forth below summarizes the net present value of future net revenue
as of December 31, 2003 based on constant price and cost assumptions.

   SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                                      NET PRESENT VALUES OF FUTURE NET REVENUE ($000s) (1)
                                                  BEFORE INCOME TAXES                     AFTER INCOME TAXES
                                                 DISCOUNTED AT (%/YEAR)                 DISCOUNTED AT (%/YEAR)
                                                     0%               10%              0%               10%
--------------------------------------------------------------------------------------------------------------
<S>                                              <C>               <C>             <C>                <C>
PROVED
Developed Producing                              $1,255,268        $611,576        $  895,448         $445,904
Developed Non-Producing                             112,896          58,704            81,323           43,023
Undeveloped                                         237,545          88,803           168,647           64,086
--------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                     $1,605,709        $759,083        $1,145,418         $553,013
--------------------------------------------------------------------------------------------------------------
</TABLE>

(1)      A portion of the Company'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, but is not included in these numbers.

Undiscounted total future net revenue calculated using constant prices and
costs, incorporates the elements presented in the table below.

TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
 RESERVES     REVENUE     ROYALTIES   OPERATING   DEVELOPMENT       WELL        FUTURE NET   INCOME      FUTURE NET
 CATEGORY     ($000s)     ($000s)       COSTS        COSTS     ABANDONMENT(1)     REVENUE      TAXES       REVENUE
                                       ($000s)      ($000s)     COSTS ($000s)     BEFORE      ($000s)   AFTER INCOME
                                                                               INCOME TAXES                 TAXES
                                                                                  ($000s)                  ($000s)
----------------------------------------------------------------------------------------------------------------------
<S>         <C>           <C>         <C>           <C>            <C>          <C>           <C>        <C>
Proved      $3,126,885    $659,281    $785,187      $64,034        $12,674      $1,605,709    $460,291   $1,145,418
----------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)      Includes, at minimum, well abandonment costs, (rather than total
         abandonment and reclamation costs).

                                      -15-
<PAGE>

The following table summarizes the Company's total future net revenue using
constant prices and costs, before income taxes, by production type.

TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
  RESERVES CATEGORY                         PRODUCTION TYPE                    FUTURE NET REVENUE BEFORE INCOME
                                                                                            TAXES
                                                                              (DISCOUNTED AT 10%/YEAR) ($000S)
-------------------------------------------------------------------------------------------------------------------
<S>                         <C>                                                           <C>
  Proved                    Crude Oil, incl Solutionn Gas and related Ngls                $ 56,931
                            Natural Gas and Ngls, excl solutionn gas & Ngls               $702,152
-------------------------------------------------------------------------------------------------------------------
</TABLE>

FORECAST PRICES AND COSTS


A summary of the Company's reserves by product type, based upon forecast price
and cost assumptions, before and after applicable royalties, excluding ARTC, at
the end of the most recent fiscal year is presented below.


SUMMARY OF OIL AND GAS RESERVES USING FORECAST PRICING AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                                    CRUDE OIL             NATURAL GAS                NGLS(1)
                                                 GROSS        NET        GROSS        NET        GROSS        NET
                                                (MBBL)      (MBBL)      (MCF)       (MCF)       (MBBL)      (MBBL)
--------------------------------------------------------------------------------------------------------------------
<S>                                              <C>         <C>        <C>         <C>           <C>         <C>
PROVED
Developed Producing                               6,530       6,059     321,893     263,312       6,592       5,037
Developed Non-Producing                             163         159      31,538      23,805         574         375
Undeveloped                                       2,494       1,945      49,324      37,838       1,121         784
--------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                      9,187       8,163     402,755     324,955       8,287       6,196
PROBABLE                                          2,847       2,016     165,298     135,347       3,745       2,860
--------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                       12,034      10,179     568,053     460,302      12,032       9,056
--------------------------------------------------------------------------------------------------------------------

(1)      Ngl volumes include sulphur volumes with a conversion rate of 1 long ton = 1 barrel.
</TABLE>


                                      -16-
<PAGE>

The table set forth below summarizes the net present value of future net revenue
as of December 31, 2003 based on forecast prices and cost assumptions.

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                                        NET PRESENT VALUES OF FUTURE NET REVENUE ($000s)
                                                                        BEFORE INCOME TAXES
                                                                      DISCOUNTED AT (%/YEAR)
                                                       0%             5%           10%          15%          20%
-------------------------------------------------------------------------------------------------------------------
<S>                                                <C>           <C>            <C>          <C>          <C>
PROVED
Developed Producing                                $1,191,078    $  705,620     $521,521     $426,393     $367,095
Developed Non-Producing                                98,228        64,489       48,080       38,372       31,878
Undeveloped                                           215,400       113,727       70,348       47,727       34,204
-------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                        1,504,706       883,836      639,949      512,492      433,177
-------------------------------------------------------------------------------------------------------------------
PROBABLE                                              605,019       310,664      188,181      125,458       88,563
-------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                         $2,109,725    $1,194,500     $828,130     $637,950     $521,740
-------------------------------------------------------------------------------------------------------------------
</TABLE>


<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                                        NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)
                                                                        AFTER INCOME TAXES
                                                                      DISCOUNTED AT (%/YEAR)
                                                       0%             5%           10%          15%          20%
-------------------------------------------------------------------------------------------------------------------
<S>                                                <C>             <C>          <C>          <C>          <C>
PROVED
Developed Producing                                $  854,329      $533,178     $392,233     $318,191     $272,853
Developed Non-Producing                                71,935        48,265       36,394       29,391       24,736
Undeveloped                                           154,078        83,604       52,268       35,914       26,175
-------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                        1,080,432       665,047      480,895      383,496      323,764
PROBABLE                                              393,829       198,237      113,350       70,357       45,568
-------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                         $1,474,171      $863,284     $594,245     $453,853     $369,332
-------------------------------------------------------------------------------------------------------------------
</TABLE>


                                      -17-
<PAGE>

Undiscounted total future net revenue calculated using forecast prices and
costs and incorporates the elements presented in the table below.

TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
   RESERVES      REVENUE   ROYALTIES  OPERATING  DEVELOP-MENT     WELL       FUTURE NET     INCOME     FUTURE NET
   CATEGORY                             COSTS       COSTS     ABANDON-MENT    REVENUE       TAXES        REVENUE
                 ($000s)    ($000s)    ($000s)     ($000s)      COSTS(1)       BEFORE      ($000s)    AFTER INCOME
                                                                ($000s)        INCOME                     TAXES
                                                                               TAXES                     ($000S)
                                                                              ($000S)
--------------------------------------------------------------------------------------------------------------------
<S>            <C>           <C>        <C>          <C>         <C>       <C>           <C>          <C>
Proved         $ 3,081,572   $ 638,840  $  858,782   $  64,524   $ 14,720  $ 1,504,706   $ 424,364    $ 1,080,342
Proved Plus
Probable       $ 4,268,903   $ 883,285  $1,057,595   $ 200,335   $ 17,963  $ 2,109,725   $ 635,554    $ 1,474,171
--------------------------------------------------------------------------------------------------------------------
</TABLE>


The following table summarizes the Company's total future net revenue using
forecast price and cost assumptions, before income taxes, by production type.

       TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                     PRODUCTION TYPE                       FUTURE NET REVENUE BEFORE INCOME TAXES
                                                                               (DISCOUNTED AT 10%/YEAR) ($000s)
--------------------------------------------------------------------------------------------------------------------
<S>                                   <C>                                                     <C>
Proved                                Crude Oil and Ngls                                      $  47,996

                                      Natural Gas                                             $ 591,953
--------------------------------------------------------------------------------------------------------------------
</TABLE>


                               PRICING ASSUMPTIONS

CONSTANT PRICES USED IN ESTIMATES

The constant price assumptions presume the continuance of current laws,
regulations and operating costs in effect on the date of the Report. Future net
revenue calculated using constant prices and costs is based upon the price
assumptions set out below. The prices are founded upon the assumptions made by
the independent engineering firm, Netherland Sewell, as at December 31, 2003.


SUMMARY OF CONSTANT PRICING ASSUMPTIONS AS OF DECEMBER 31, 2003

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                CRUDE OIL                 NATURAL GAS                               NGLS                    SULPHUR
    YEAR      EDMONTON PAR   AECO-C SPOT  TRANSCANADA   PAN-ALBERTA   PROPANE      BUTANE     PENTANES+   PLANT GATE
             40 DEGREES API    ($CDN/)        GAS       ($CDN/MCF)   ($CDN/BBL)  ($CDN/BBL)  ($CDN/BBL)    ($CDN/LONG
              ($CDN/BBL)       MMBTU)     ($CDN/MCF)                                                          TON)
---------------------------------------------------------------------------------------------------------------------
<S>               <C>           <C>          <C>           <C>         <C>        <C>         <C>          <C>
Dec 31, 2003      $39.25        $6.09        $4.67         $4.67       $31.78     $38.93      $44.49         $26.25
---------------------------------------------------------------------------------------------------------------------
</TABLE>


FORECAST PRICES USED IN ESTIMATES

Future net revenue calculated using forecast prices and costs is based upon the
price assumptions set out below. As an independent reserves evaluator,
Netherland Sewell does not provide price forecasts. December 31, 2003 pricing
forecasts prepared by Sproule Associates Limited were utilized in estimating
Compton's reserves data using forecast pricing and costs.


                                      -18-
<PAGE>


SUMMARY OF FORECAST PRICING AND INFLATION RATE ASSUMPTIONS AS OF DECEMBER 31,
2003

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------------------
   YEAR          CRUDE OIL                  NATURAL GAS                             NGLS                   SULPHUR

               EDMONTON PAR   AECO-C SPOT   TRANS-CANADA  PAN-ALBERTA    PROPANE    BUTANE     PENTANES+    PLANT     INFLATION
              40 DEGREES API  ($CDN/MCF)        GAS       ($CDN/MCF)   ($CDN/BBL) ($CDN/BBL)  ($CDN/BBL)     GATE       RATE (1)
               ($CDN/BBL)                   ($CDN/MCF)                                                   ($CDN/LONG     %/YEAR
                                                                                                             TON)
--------------------------------------------------------------------------------------------------------------------------------
<S>               <C>            <C>           <C>           <C>         <C>        <C>          <C>        <C>          <C>
FORECAST
2004              $37.99         $6.04         $5.74         $5.74       $28.04     $31.15       $38.91     $40.00       1.5%
2005              $34.24         $5.36         $5.11         $5.11       $22.56     $25.52       $35.07     $30.45       1.5%
2006              $32.87         $4.80         $4.57         $4.57       $20.58     $23.28       $33.67     $20.60       1.5%
2007              $33.37         $4.91         $4.67         $4.67       $20.89     $23.63       $34.17     $15.69       1.5%
2008              $33.87         $4.98         $4.78         $4.78       $21.20     $23.98       $34.69     $15.92       1.5%
2009              $34.38         $5.05         $4.87         $4.87       $21.52     $24.34       $35.21     $16.16       1.5%
2010              $34.90         $5.14         $4.96         $4.96       $21.85     $24.71       $35.74     $16.40       1.5%
2011              $35.43         $5.24         $5.05         $5.05       $22.18     $25.08       $36.28     $16.65       1.5%
2012              $35.96         $5.33         $5.14         $5.14       $22.51     $25.46       $36.83     $16.90       1.5%
2013              $36.50         $5.43         $5.24         $5.24       $22.85     $25.85       $37.38     $17.15       1.5%
2014              $37.05         $5.52         $5.33         $5.33       $23.20     $26.24       $37.95     $17.41       1.5%
2015              $37.61         $5.62         $5.43         $5.43       $23.55     $26.63       $38.52     $17.67       1.5%
THEREAFTER          1.5%          1.5%          1.5%          1.5%         1.5%       1.5%         1.5%       1.5%       1.5%
--------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1)   Inflation rates for forecasting prices. Operating costs and capital
      investments are escalated at 0.75% per year.

The weighted average realized sale price for Compton for the year ended December
31, 2003 were $6.01/mcf for natural gas, $34.19/bbl for crude oil and $33.14/bbl
for ngls.

RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE

RESERVES RECONCILIATION

The following table provides a summary of the changes in the Company's reserves
which occurred in the most recent fiscal year, based upon escalated price and
cost assumptions, net of applicable royalties.

RECONCILIATION OF NET RESERVES BY PRODUCT TYPE USING FORECAST PRICES AND
COSTS(1)

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                            CRUDE OIL AND NGLS                           NATURAL GAS

                                       NET        NET          NET PROVED       NET           NET        NET PROVED
                                     PROVED   PROBABLE       PLUS PROBABLE     PROVED      PROBABLE     PLUS PROBABLE
                                      (mbbl)    (mbbl)          (mbbl)         (mmcf)       (mmcf)         (mmcf)
---------------------------------------------------------------------------------------------------------------------
<S>                                  <C>          <C>              <C>         <C>          <C>              <C>
December 31, 2002                    11,884       4,116            16,000      310,419      72,512           382,931
Extensions                            1,397           0             1,397        9,940         226            10,166
Improved Recovery                       810         139               949        6,595        (293)            6,302
Technical Revisions                     683        (863)             (180)     (10,443)        861            (9,582)
Discoveries                             661       1,180             1,841       37,593      62,670           100,263
Acquisitions                            404           0               404        2,333           0             2,333
Dispositions                              0           0                 0            0           0                 0
Economic                                344         304               648           86        (629)             (543)
Production                           (1,824)          0            (1,824)     (31,568)          0           (31,568)
---------------------------------------------------------------------------------------------------------------------
December 31, 2003                    14,359       4,876            19,235      324,955     135,347           460,302
---------------------------------------------------------------------------------------------------------------------
(1)    Prepared by Management.
</TABLE>


                                      -19-
<PAGE>

FUTURE NET REVENUE RECONCILIATION


The following table reconciles changes between the future net revenue estimates
at December 31, 2003 and the corresponding estimates in the prior year, using
constant prices and costs, discounted at 10%.


RECONCILIATION OF CHANGES IN NET PRESENT VALUE OF FUTURE NET REVENUE OF PROVED
RESERVES (1)

<TABLE>
<CAPTION>
                                                                                                   2003
                                                                                                  ($000s)(2)
------------------------------------------------------------------------------------------------------------
<S>                                                                                              <C>
Estimated Future Net Revenue at Beginning of Year                                                $1,016,120
Sales and Transfers of Oil and Gas Produced, Net of Production Costs and Royalties                 (197,323)
Net Change in Prices, Production Costs and Royalties Related to Future Production                  (273,632)
Changes in Previously Estimated Development Costs Incurred During the Period                        (85,586)
Changes in Estimated Future Development Costs                                                       (39,965)
Extensions and Improved Recovery                                                                     52,043
Discoveries                                                                                          92,522
Acquisitions of Reserves                                                                              6,328
Dispositions of Reserves                                                                                  0
Net Change Resulting from Revisions in Quantity Estimates                                           (69,386)
Accretion of Discount                                                                               101,612
Net Change in Income Taxes(3)                                                                       156,350
------------------------------------------------------------------------------------------------------------
Estimated Future Net Revenue at End of Year                                                      $  759,083
------------------------------------------------------------------------------------------------------------
</TABLE>
(1)      Prepared by Management.
(2)      Except for "Net Change in Income Taxes", the amounts above are before
         tax.
(3)      Includes both income taxes incurred during the period and changes in
         estimated future income tax expenses.


                ADDITIONAL INFORMATION RELATING TO RESERVES DATA


UNDEVELOPED RESERVES

The following discussion generally describes the basis on which Compton
attributes Proved and Probable Undeveloped Reserves and its plans for developing
those Undeveloped Reserves.

PROVED UNDEVELOPED RESERVES

Proved undeveloped reserves are generally those reserves related to wells that
have been tested and not yet tied-in, wells drilled near the end of the fiscal
year or wells further away from the Company's gathering systems. In addition,
such reserves may relate to planned infill drilling locations. The majority of
these reserves are planned to be on stream within a two year timeframe.

PROBABLE UNDEVELOPED RESERVES

Probable undeveloped reserves are generally those reserves tested or indicated
by analogy to be productive infill drilling locations and lands contiguous to
production. The majority of these reserves are planned to be on stream within a
two year timeframe.

SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA

The process of estimating reserves is complex. It requires significant judgments
and decisions based on available geological, geophysical, engineering and
economic data. These estimates may change substantially as additional data from
ongoing development activities and production performance becomes available and
as economic


                                      -20-
<PAGE>

conditions impacting oil and natural gas prices and costs change. The reserve
estimates contained herein are based on current production forecasts, prices and
economic conditions. Compton's reserves are evaluated by Netherland Sewell.

As circumstances change and additional data becomes available, reserve estimates
also change. Estimates made are reviewed and revised, either upward or downward,
as warranted by the new information. Revisions are often required due to changes
in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are
accurate, reserve estimation is an inferential science. As a result, subjective
decisions, new geological or production information and a changing environment
may impact these estimates. Revisions to reserve estimates can arise from
changes in year-end oil and natural gas prices, and reservoir performance. Such
revisions can be either positive or negative.

FUTURE DEVELOPMENT COSTS

The following table provides a summary of the development costs deducted in the
estimation of future net revenue attributable to each of the following reserves
categories:

DEVELOPMENT COSTS DEDUCTED IN ESTIMATING FUTURE NET REVENUES

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
YEAR                                                   PROVED                              PROVED PLUS PROBABLE

                                   CONSTANT PRICES AND         FORECAST PRICES AND         FORECAST PRICES AND
                                   COSTS/YEAR ($000S)          COSTS/YEAR ($000S)           COSTS/YEAR ($000S)
--------------------------------------------------------------------------------------------------------------------
<S>                                        <C>                        <C>                           <C>
Undiscounted
   2004                                    $36,746                    $36,859                       $ 94,522
   2005                                    $18,945                    $19,148                       $ 54,814
   2006                                    $ 8,080                    $ 8,400                       $ 30,687
   2007                                    $   486                    $   816                       $ 11,988
   2008                                    $ 1,336                    $ 1,459                       $  9,803
   Remaining                               $11,116                    $12,563                       $ 16,483
--------------------------------------------------------------------------------------------------------------------
Total Undiscounted                         $76,709                    $79,245                       $218,297

Total Discounted at 10%                    $62,547                    $63,607                       $181,256
per Year
--------------------------------------------------------------------------------------------------------------------
</TABLE>

Compton estimates that its internally generated cash flow will be sufficient to
fund the future development costs disclosed above. Compton typically has
available three sources of funding to finance its capital expenditure program:
(i) internally generated cash flow from operations; (ii) debt financing when
appropriate; and (iii) new equity issues, if available on favourable terms.

Compton expects to fund its total 2004 capital program with internally generated
cash flow, bank debt and minor property dispositions.


                                      -21-
<PAGE>

OIL AND GAS PROPERTIES AND WELLS

The following table summarizes the location of the Company's interests as at
December 31, 2003, in crude oil and natural gas wells which are producing or
which the Company considers to be capable of production.

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
AREA                      PRODUCING CRUDE     SHUT-IN CRUDE       PRODUCING      SHUT-IN NATURAL        TOTAL
                             OIL WELLS        OIL WELLS(1)       NATURAL GAS       GAS WELLS (1)
                                                                    WELLS

                           GROSS     NET     GROSS      NET     GROSS     NET     GROSS     NET     GROSS     NET
--------------------------------------------------------------------------------------------------------------------
<S>                           <C>      <C>        <C>      <C>      <C>     <C>      <C>       <C>   <C>      <C>
ALBERTA
South                          75       31        13        5       323     268       16        9      427    313.2
Central                       160       78        28       11       345     116       53       12      586    216.7
PRA                           164       94        46       20        89      37       32       13      331    163.4
BC                              0        0         0        0        30       3        4        0       34      3.3
--------------------------------------------------------------------------------------------------------------------
TOTAL O&G WELLS               399      203        87       36       787     424      105       34    1,378    696.6
--------------------------------------------------------------------------------------------------------------------
</TABLE>

PROPERTIES WITH NO ATTRIBUTED RESERVES

The following table sets forth the Company's undeveloped land holdings to which
no proved reserves have been attributed as at December 31, 2003.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------
AREA                                                           GROSS ACRES        NET ACRES
------------------------------------------------------------------------------------------------
<S>                                                             <C>                 <C>
British Columbia                                                   33,615             8,274
Alberta                                                           999,016           749,878
Manitoba                                                           10,171             9,212
------------------------------------------------------------------------------------------------
Total                                                           1,042,802           767,364
------------------------------------------------------------------------------------------------
</TABLE>

Approximately 152,300 net acres of undeveloped land could expire by December 31,
2004. However, the Company's 2004 exploration and development activities may
defer the expiry of a portion of these lands. Compton has approximately $2
million of work commitments associated with unproved properties.

FORWARD CONTRACTS

In 2003, Compton's realized average field price, including hedge losses, was
$35.66/boe, comprised of $6.01/mcf for natural gas and $34.39/bbl for liquids
(crude oil and ngls). In 2002, the average field prices of natural gas and
liquids were $3.67/mcf and $29.43/bbl, respectively, for an average price of
$23.95/boe.

Compton's natural gas production is sold under a combination of longer term
contracts with aggregators and short term daily or 30 day AECO indexed
contracts. Approximately 16% of the Company's natural gas production in 2003 was
committed to aggregators. The average aggregator price realized was
approximately $1.00/mcf less than the non-aggregator prices realized during the
year. Compton is pursuing winding-up of the contracts in late 2004. It is likely
the Company will incur costs with the wind up of the aggregator pools, however,
such costs cannot be estimated at this time.

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

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.


                                      -22-
<PAGE>

ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS

Compton is required to remove production equipment, batteries, pipelines and
natural gas plants and to restore land at the end of oil and natural gas
operations. The Company estimates these costs in accordance with existing laws,
contracts and other policies. These obligations are initially measured at fair
value, which is the discounted future value of the liability. This fair value is
also capitalized as part of the cost of the related assets and amortized over
the useful life of the assets.

An independent environmental consulting firm was hired to assist Management in
the estimation of the Company's asset retirement obligation ("ARO"). ARO cost
calculations were derived from a combination of actual third party cost quotes,
Alberta Energy and Utility Board cost models and typical industry experience and
practices. The deemed ARO liability for Compton's 975 net wells and facilities
is the sum of the calculated abandonment and reclamation liabilities adjusted
for designated status as active, inactive, abandoned or problem site.
Information regarding environmental remediation costs and other liability issues
for site specific concerns were derived from a review of historical audit and
assessment reports of sites and facilities. An inflation rate of 2% and a credit
adjusted risk free rate of 10.6% was used in the fair value calculation.

Total asset retirement costs, net of estimated salvage values, is $66 million or
$14 million when discounted at 10%. The undiscounted ARO associated with
pipelines and facilities is $10 million and is not deducted in estimating total
future net revenue, as calculated in the Company's reserve report. The Company
expects to pay $1 million dollars in ARO costs between 2004 and 2007.

TAX HORIZON

The Company may be marginally cash taxable in 2004, depending upon the nature
and level of capital expenditures and commodity prices.

CAPITAL EXPENDITURES

In 2003, Compton incurred $54 million of exploration costs and $72 million of
development costs. Additionally, $11 million was spent on proved property
acquisitions and $2 million was spent on unproved property acquisitions.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The following table sets forth the number of crude oil, natural gas and service
wells drilled by the Company, or which the Company 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, 2003 and 2002. Seven wells drilled in 2003 are standing cased wells
and are awaiting completion and testing. These wells are not included in the
following table.


<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
                                            YEAR ENDED DECEMBER 31, 2003           YEAR ENDED DECEMBER 31, 2002

                                            DEVELOPMENT        EXPLORATORY        DEVELOPMENT        EXPLORATORY

                                          GROSS      NET      GROSS     NET     GROSS      NET     GROSS      NET
--------------------------------------------------------------------------------------------------------------------
<S>                                        <C>        <C> <C>   <C>      <C>      <C>      <C>  <C>  <C>      <C>
Crude Oil                                  17         11         1        1       13       11         1        1
Natural Gas                                67         46        48       45       41       28        23       17
Dry and Abandoned                           9          8        19       18        3        3         6        4
--------------------------------------------------------------------------------------------------------------------
TOTAL                                      93         65        68       64       57       42        30       22
SUCCESS RATIO                                             83%                                   90%
--------------------------------------------------------------------------------------------------------------------
</TABLE>

In 2004, the Company will continue to focus its resources in Alberta, Canada.
Priority will be given to drilling commitments, on-stream timing and growth in
core areas and land retention. In Southern Alberta, 112 wells are budgeted at a
cost of $137 million. Compton plans to drill 74 Belly River natural gas wells in
the Centron/Gladys/Brant area and 24 wells in the Hooker Basal Quartz trend. The
Company has budgeted 35 wells in


                                      -23-
<PAGE>

Central Alberta with a capital expenditures budget of $34 million, targeting the
Gething and Rock Creek sands at Niton and the McMurray zone at Thornbury. In the
Peace River Arch, 28 wells were planned at a cost of $21 million. Compton has 16
wells planned at Cecil / Worsely and seven Dunvegan wells at Howard.
Additionally, 15 wells are budgeted for minor properties, outside of the
Company's core areas.

PRODUCTION HISTORY

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

GROSS NATURAL GAS AND LIQUIDS (CRUDE OIL AND NGLS) PRODUCTION

<TABLE>
<CAPTION>
------------------------------------------- ------------------------------------------------------------------------
PRODUCT TYPE                                             FISCAL 2003 THREE MONTHS ENDED                   TOTAL
                                                                                                           2003
                                             MARCH 31,      JUNE 30,       SEPTEMBER    DECEMBER 31,
                                                2003          2003         30, 2003         2003
------------------------------------------- ------------------------------------------------------------------------
<S>                                            <C>            <C>            <C>            <C>           <C>
Natural Gas (mmcfd)                               119            119            111            123           118
Natural Gas (mmcf)                             10,684         10,783         10,217         11,302        42,986

Liquids (Crude Oil & Ngls)  (bopd)              6,068          5,910          5,710          6,010         5,924
Liquids (Crude Oil & Ngls)  (mbbls)               546            538            525            553         2,162
------------------------------------------- ------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
------------------------------------------- ------------------------------------------------------------------------
PRODUCT TYPE                                             FISCAL 2002 THREE MONTHS ENDED                   TOTAL
                                                                                                           2002
                                             MARCH 31,      JUNE 30,       SEPTEMBER    DECEMBER 31,
                                                2002          2002         30, 2002         2002
------------------------------------------- ------------------------------------------------------------------------
<S>                                             <C>            <C>           <C>            <C>             <C>
Natural Gas (mmcfd)                               107            109            110            121             112
Natural Gas (mmcf)                              9,640          9,919         10,138         11,141          40,838

Liquids (Crude Oil & Ngls) (bopd)               6,598          6,610          6,417          6,390           6,503
Liquids (Crude Oil & Ngls) (mbbls)                594            602            590            588           2,374
------------------------------------------- ------------------------------------------------------------------------
</TABLE>

2004 PRODUCTION ESTIMATES

Production volumes in 2004 as estimated in the reserve forecast before deduction
of royalties are set forth below. Production volumes are the same in both the
constant price case and the forecast price cases.

--------------------------------------------------------------------------------
RESERVES CATEGORY                                   NATURAL GAS      LIQUIDS(1)
                                                     (MMCFD)          (BBLD)
--------------------------------------------------------------------------------
PROVED
Developed Producing                                       78          4,110
Developed Non-Producing                                   12            254
Undeveloped                                                3            429
--------------------------------------------------------------------------------
TOTAL PROVED                                              93          4,793
PROBABLE                                                  21            531
--------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                               114          5,324
--------------------------------------------------------------------------------

(1)      Ngl volumes include sulphur volumes with a conversion rate of 1 long
         ton = 1 barrel.


                                      -24-
<PAGE>

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

NATURAL GAS AND LIQUIDS (CRUDE OIL AND NGLS) FIELD NETBACKS

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
                                                          FISCAL 2003 THREE MONTHS ENDED
                                             MARCH 31,      JUNE 30,       SEPTEMBER     DECEMBER 31,      TOTAL
                                                2003          2003         30, 2003          2003          2003
--------------------------------------------------------------------------------------------------------------------
<S>                                           <C>           <C>             <C>            <C>            <C>
NATURAL GAS ($/MCF)
Revenue Price                                 $ 6.83        $ 6.08          $ 5.62         $ 5.52         $ 6.01
Royalties, Net                                 (1.64)        (1.49)          (1.38)         (1.36)         (1.48)
Operating Costs                                (0.87)        (0.92)          (0.97)         (0.99)         (0.93)
--------------------------------------------------------------------------------------------------------------------
Field Netback                                 $ 4.32        $ 3.67          $ 3.27         $ 3.17         $ 3.60

LIQUIDS (CRUDE OIL & NGLS) ($/BBL)
Revenue Price                                 $35.62        $33.03          $35.06         $33.88         $34.39
Royalties, Net                                 (9.85)        (8.95)          (8.29)         (8.33)         (8.85)
Operating Costs                                (5.21)        (5.54)          (5.79)         (5.75)         (5.57)
--------------------------------------------------------------------------------------------------------------------
Field Netback                                 $20.56        $18.54          $20.98         $19.80         $19.97
--------------------------------------------------------------------------------------------------------------------
</TABLE>

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
                                                         FISCAL 2002 THREE MONTHS ENDED
                                             MARCH 31,      JUNE 30,       SEPTEMBER    DECEMBER 31,      TOTAL
                                                2002          2002         30, 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                                (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 & NGLS)  ($/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                                (4.69)        (5.13)          (5.05)         (4.98)        (4.96)
--------------------------------------------------------------------------------------------------------------------
Field Netback                                 $14.45        $18.73          $19.09         $20.28        $18.13
--------------------------------------------------------------------------------------------------------------------
</TABLE>


                                    DIVIDENDS

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.


                                CAPITAL STRUCTURE

Compton is authorized to issue an unlimited number of common shares and an
unlimited number of preferred shares, of which 117,311,648 common shares are
issued and outstanding as fully paid and non-assessable shares.


                                      -25-
<PAGE>

No preferred shares are issued and outstanding as at May 14, 2004. The following
is a description of Company's common and preferred shares.

COMMON SHARES

Common shares have attached to them the following rights, privileges,
restrictions and conditions: (i) except for meetings at which only holders of
another specified class or series of shares of the Company are entitled to vote
separately as a class or series, each holder of a common share is entitled to
receive notice of, to attend and to vote at all meetings of the shareholders of
the Company; (ii) subject to the rights, privileges, restrictions and conditions
attached to any preferred shares, the holders of common shares are entitled to
receive dividends if, and when declared by the Directors of the Company; and
(iii) subject to the rights, privileges, restrictions and conditions attached to
any other class of shares of the Company, the holders of common shares are
entitled to share equally in the remaining property of the Company upon
liquidation, dissolution or winding-up of the Company.

PREFERRED SHARES

The preferred shares may be issued in one or more series, and the Directors are
authorized to fix the number of shares in each series and to determine the
designation, rights, privileges, restrictions and conditions attached to the
shares of each series. The preferred shares are entitled to a priority over the
common shares with respect to the payment of dividends and the distribution of
assets upon the liquidation, dissolution or winding-up of Compton.


                                      -26-
<PAGE>

                              MARKET FOR SECURITIES


The outstanding common shares of the Company 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. The
following table sets out the price range for and average trading volume of
common shares as reported by the Toronto Stock Exchange, as applicable, for the
periods indicated.

--------------------------------------------------------------------------------
         PERIOD                 HIGH            LOW             VOLUME
--------------------------------------------------------------------------------

2003
  January                       $5.02           $4.87             678,799
  February                      $5.28           $5.12             877,001
  March                         $5.21           $5.04             514,846
  April                         $5.16           $5.00             640,424
  May                           $5.75           $5.58             903,831
  June                          $6.05           $5.87             870,707
  July                          $5.76           $5.62             720,899
  August                        $6.17           $6.01             615,510
  September                     $5.96           $5.80             620,746
  October                       $5.96           $5.83             570,891
  November                      $5.63           $5.50             745,436
  December                      $6.00           $5.86             486,956

2004
  January                       $6.73           $6.50           1,167,334
  February                      $7.33           $7.14             871,891
  March                         $7.93           $7.68             534,715
  April                         $8.82           $7.20             580,507
  May 1 - 14                    $7.71           $6.55             584,046
--------------------------------------------------------------------------------


                              CONFLICTS OF INTEREST


The Directors and officers of Compton are engaged in and will continue to engage
in other activities in the oil and natural gas industry and as a result of these
and other activities, the Directors and officers of Compton may become subject
to conflicts of interest. The Business Corporations Act (Alberta) (the "ACT")
provides that in the event that a director has an interest in a contract or
proposed contract or agreement, the director shall disclose his interest in such
contract or agreement and shall refrain from voting on any matter in respect of
such contract or agreement unless otherwise provided under the Act. To the
extent that conflicts of interest arise, such conflicts will be resolved in
accordance with the provisions of the Act. As at the date hereof, Compton is not
aware of any existing or potential material conflicts of interest between
Compton and a director or officer of the Company.


           INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS


None of the current executive officers or Directors of Compton, and no person or
company owning or exercising control over more than 10% of the common shares of
Compton; nor any associate or affiliate of the foregoing has or


                                      -27-
<PAGE>

has had, at any time, any material interest, direct or indirect, in any
transaction or proposed transaction that has materially affected or would
materially affect Compton.


                              INTERESTS OF EXPERTS

As at the date hereof, the partners and associates of Grant Thornton, LLP, the
auditors of Compton, as a group, did not beneficially own any of Compton's
outstanding shares. As at the date hereof, principals of Netherland Sewell
personally disclosed in certificates of qualification that they neither had, nor
expected to receive, any of the Company's outstanding shares.


                                     RATINGS

Standard & Poor's Rating Services and Moody's Corporation have rated Compton's
U.S. denominated 9.9% senior notes as "B" and "B2" respectively, as at December
31, 2003. A security rating is not a recommendation to buy, sell or hold
securities and may be subject to revisions or withdrawal at any time by the
rating agency.


                             DIRECTORS AND OFFICERS


DIRECTORS

Information is given below with respect to each of the current Directors of the
Company. All Directors of Compton stand for election at each annual meeting of
the Company. The next Annual and Special Meeting of Shareholders is scheduled
for June 17, 2004 at 4:00 pm. (Calgary time) in The Devonian Room, Calgary
Petroleum Club, 319 - 5th Avenue S.W., 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 Company, other than Mr. Sapieha, each of whom is an independent, outside and
unrelated Director.


                                      -28-
<PAGE>

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

<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
NAME AND MUNICIPALITY OF                              PRINCIPAL OCCUPATION                           DIRECTOR SINCE
RESIDENCE
--------------------------------------------------------------------------------------------------------------------
<S>                          <C>                                                                          <C>
Mel F. Belich, Q.C.          Chairman and President of Enbridge International Inc. and Enbridge           1993
Calgary, Alberta             Technology Inc., and Group Vice President - International and
                             Corporate Law, Enbridge Inc., an energy transportation and
                             distribution company.

                             Mr. Belich is the Chairman of the Board of Directors of Compton and
                             the Chairman of the Governance and Compensation Committee.
--------------------------------------------------------------------------------------------------------------------
Irvine J. Koop, P. Eng.      Chairman and Chief Executive Officer, IKO Resources Inc., a petroleum        1996
Calgary, Alberta             consulting firm and prior thereto, President and CEO, Pipelines and
                             Midstream of Westcoast Energy Inc.

                             Mr. Koop is the Chairman of the Audit, Finance and Risk Committee.
--------------------------------------------------------------------------------------------------------------------
John W. Preston              Account Executive, Sun Microsystems of Canada Inc., a computer               1993
Calgary, Alberta             company.
--------------------------------------------------------------------------------------------------------------------
Jeffrey T. Smith, P. Geol.   Independent Businessman and prior thereto, Chief Operating Officer of        1999
Calgary, Alberta             Northstar Energy Corporation.

                             Mr. Smith is Chairman of the Engineering, Environmental, Health and
                             Safety Committee.
--------------------------------------------------------------------------------------------------------------------
Ernest G. Sapieha, C.A.      President & Chief Executive Officer of the Company.                          1993
Calgary, Alberta
--------------------------------------------------------------------------------------------------------------------
John A. Thomson, C.A.        Independent Businessman and prior thereto, Senior Vice President and         2003
Calgary, Alberta             Chief Financial Officer of Renaissance Energy Ltd.
--------------------------------------------------------------------------------------------------------------------
</TABLE>

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 3
of the Company's Management Proxy Circular dated May 3, 2004 relating to the
Annual and Special Meeting of Shareholders to be held on June 17, 2004, which
sections are incorporated by reference into this Annual Information Form.


                                      -29-
<PAGE>

OFFICERS

The name, city of residence and principal occupation during the last five years
of each of the officers of the Company 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 Company.
Calgary, Alberta

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

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

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

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

Marc R. Junghans, P. Geol.             Vice President, Exploration, prior to 2003, Manager of Exploration of the
Calgary, Alberta                       Company.

Derek Longfield, P. Eng.               Vice President, Special Projects of the Company, prior to 2003, Manager of
Calgary, Alberta                       Engineering of the Company.

--------------------------------------------------------------------------------------------------------------------
</TABLE>

As at May 3, 2004, the Directors and officers of Compton as a group beneficially
owned or controlled, directly or indirectly, 11,285,459 common shares of
Compton, representing approximately 9.6% of the issued and outstanding common
shares of the Company on a fully diluted basis. None of the Directors or
officers held a sufficient number of common shares to materially affect the
control of Compton.


                  AUDIT, FINANCE AND RISK COMMITTEE INFORMATION

The Charter of the Audit, Finance and Risk Committee is set forth in Schedule C.

COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE

Chairman: Irvine J. Koop
Members: Mel F. Belich, John W. Preston, Jeffrey T. Smith and John A. Thomson

All members of the Audit, Finance and Risk Committee are independent, unrelated,
outside Directors. An "independent" director is a director who has no direct or
indirect material relationship with the Company (a material relationship is a
relationship which could, in the view of the Board, reasonably interfere with
the exercise of a director's independent judgment).

An "unrelated" Director is a director who is (a) not a member of Management and
is free from any interest and any business, family or other relationship which
could, or could reasonably be perceived to, materially interfere with the
Director's ability to act with a view to the best interests of the Company,
other than interests and relationships arising from shareholding, (b) not
currently or has not been, within the last three years, an officer, employee of
or


                                      -30-
<PAGE>

material service provider to the Company or any of its subsidiaries or
affiliates, and (c) not a director, officer employee or significant shareholder
of an entity that has a material business relationship with the Company.

An "outside" Director is not a member of the Company's Management. Additionally,
no Board members sit on other boards together, in order that there are no
inter-related interests.

Mr. Thomson is considered to be a "financial expert", as defined in National
Instrument 52-110, due to his experience in the oil and natural gas industry as
a Chartered Accountant, as Chief Financial Officer of a major public oil and
natural gas company, and as a board member and Officer for other public
reporting oil and natural gas companies. All other Committee members are
"financially literate", as defined in National Instrument 52-110.


EXTERNAL AUDITOR FEES

The aggregate amounts paid or accrued by the Company with respect to fees
payable to Grant Thornton for audit and audit-related (including separate audits
of subsidiary entities, financings and regulatory reporting requirements), tax
and other services in the fiscal years ended December 31, 2003 and 2002 were as
follows:

--------------------------------------------------------------------------------
TYPE OF SERVICE                            FISCAL 2003          FISCAL 2002
--------------------------------------------------------------------------------
Audit                                         $286,934             $168,851
Audit Related                                   26,349              209,003
Tax                                                872                    0
Other Non-Audit                                 12,900               10,647
--------------------------------------------------------------------------------
Total                                         $327,055             $388,501
--------------------------------------------------------------------------------

The audit related fees paid in fiscal 2002 and 2003 related to the issuance of
the Company's US$ senior term notes in May 2002. Tax fees paid in fiscal 2003
related to the review of tax forms and the fees for other non-audit services in
fiscal 2003 and 2002 were incurred to translate the Company's quarterly and
annual reports into French.

The Audit, Finance and Risk Committee of the Company considered these fees and
determined that they were reasonable and do not impact the independence of the
Company's auditors. Further, such Committee determined that in order to ensure
the continued independence of the auditors, only limited non-audit related
services would be provided to the Company by Grant Thornton and in such case,
only with the prior approval of the Audit, Finance and Risk Committee. The
Committee has pre-approved Management to retain Grant Thornton to provide
miscellaneous, minor, non-audit services in circumstances where it is not
feasible or practical to convene a meeting of the Audit, Finance and Risk
Committee, subject to an aggregate limit of $20,000 per quarter.


                          TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Company's shares is Computershare Trust
Company of Canada at its office in Calgary, Alberta.

                                  RISK FACTORS


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 core areas in Western
Canada with high working interests and assuming operatorship of key facilities.
The Company utilizes a team of highly qualified professionals with expertise and
experience in these areas. Compton assesses strategic


                                      -31-
<PAGE>

acquisitions to complement existing activities while 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. However, the Company's product
mix is diversified to reduce exposure to any one commodity's price movements.
Sales of oil and natural gas are aimed at various markets to avoid undue
exposure to any one market. When appropriate, Compton ensures that parental
guarantees or letter of credit are in place to minimize the impact in the event
of default.

Compton monitors and focuses its expenditures to reflect price and production
changes. Compton continuously scrutinizes 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. 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 favorable 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.

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.


                             ADDITIONAL INFORMATION

Additional information including Directors' and officers' remuneration and
indebtedness, principal holders of the Company's common shares, options to
acquire common shares and interests of insiders in material transactions (if
applicable) is contained in the Management Proxy Circular issued by Management
dated May 3, 2004, relating to the Annual and Special Meeting of Shareholders to
be held on June 17, 2004. Additional financial information is also provided in
the consolidated financial statements of the Company for the year ended December
31, 2003 included in the Company's 2003 Annual Report. Copies of these documents
have been filed with the Canadian Securities Administrators' System for
Electronic Document Analysis and Retrieval ("SEDAR") at WWW.SEDAR.COM.


                                      -32-
<PAGE>

Additional copies of this Annual Information Form are available to the public
and may be obtained by contacting:

                  Compton Petroleum Company
                  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


                                      -33-
<PAGE>

                                   SCHEDULE A


                                 FORM 51-101F2
                     REPORT ON RESERVES DATA BY INDEPENDENT
                          QUALIFIED RESERVES EVALUATOR

To the board of directors of Compton Petroleum Corporation (the "COMPANY"):

1.       We have evaluated the Company's reserves data as at January 1, 2004.
         The reserves data consist of the following:

(a)
         (i)      proved and proved plus probable oil and gas reserves estimated
                  as at January 1, 2004 using forecast prices and costs; and

         (ii)     the related estimated future net revenue; and

(b)
         (i)      proved oil and gas reserves estimated as at January 1, 2004
                  using constant prices and costs; and

         (ii)     the related estimated future net revenue.

2.       The reserves data are the responsibility of the Company's management.
         Our responsibility is to express an opinion on the reserves data based
         on our evaluation.

         We carried out our evaluation in accordance with standards set out in
         the Canadian Oil and Gas Evaluation Handbook (the "COGE HANDBOOK")
         prepared jointly by the Society of Petroleum Evaluation Engineers
         (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy &
         Petroleum (Petroleum Society).

3.       Those standards require that we plan and perform an evaluation to
         obtain reasonable assurance as to whether the reserves data are free of
         material misstatement. An evaluation also includes assessing whether
         the reserves data are in accordance with principles and definitions
         presented in the COGE Handbook.

4.       The following table sets forth the estimated future net revenue (before
         deduction of income taxes) attributed to proved plus probable reserves,
         estimated using forecast prices and costs and calculated using a
         discount rate of 10 percent, included in the reserves data of the
         Company evaluated by us for the year ended December 31, 2003 and
         identifies the respective portions thereof that we have audited,
         evaluated and reviewed and reported on to the Company's board of
         directors:

<TABLE>
<CAPTION>
                                   Description and                Net Present Value of Future Net Revenue (before
          Independent Qualified   Preparation Date   Location             income taxes, 10% discount rate
          Reserves Evaluator or     of Evaluation    of           --------------------------------------------------
                 Auditor               Report        Reserves   Audited     Evaluated     Reviewed        Total
         -----------------------------------------------------------------------------------------------------------
<S>                                <C>               <C>          <C>    <C>                <C>       <C>
         Netherland, Sewell &
           Associates, Inc.        April 5, 2004     Canada       nil     828,129,800       nil         828,129,800
</TABLE>

5.       In our opinion, the reserves data respectively evaluated by us have, in
         all material respects, been determined and are in accordance with the
         COGE Handbook. We express no opinion on the reserves data that we
         reviewed but did not audit or evaluate.

6.       We have no responsibility to update our reports referred to in
         paragraph 4 for events and circumstances occurring after their
         respective preparation dates.


                                      -34-
<PAGE>

7.       Because the reserves data are based on judgements regarding future
         events, actual results will vary and the variations may be material.


Executed as to our report referred to above:


                                    NETHERLAND, SEWELL & ASSOCIATES, INC.
                                    Dallas, Texas, USA
                                    May 13, 2004


                                    /s/ Frederic D. Sewell
                                    -------------------------------------------
                                    Frederic D. Sewell
                                    Chairman and Chief Executive Officer


RCB:JMO



                                      -35-
<PAGE>

                                   SCHEDULE B


                       REPORT OF MANAGEMENT AND DIRECTORS
                      ON RESERVES ON OIL AND GAS DISCLOSURE


Management of Compton Petroleum Corporation (the "COMPANY") are responsible for
the preparation and disclosure of information with respect to the Company's oil
and gas activities in accordance with securities regulatory requirements. This
information includes reserves data, which consist of the following:

         (a)

                  (i)      proved and proved plus probable oil and gas reserves
                           estimated as at December 31, 2003 using forecast
                           prices and costs; and

                  (ii)     the related estimated future net revenue; and

         (b)

                  (i)      proved oil and gas reserves estimated as at December
                           31, 2003 using constant prices and costs; and

                  (ii)     the related estimated future net revenue.

An independent qualified reserves evaluator has evaluated the Company's reserves
data. The report of the independent qualified reserves evaluator will be filed
with securities regulatory authorities concurrently with this report.

The Engineering, Environmental, Health and Safety Committee of the Board of
Directors of the Company has

         (c)      reviewed the Company's procedures for providing information to
                  the independent qualified reserves evaluator;

         (d)      met with the independent qualified reserves evaluator to
                  determine whether any restrictions affected the ability of the
                  independent qualified reserves evaluator to report without
                  reservation; and

         (e)      reviewed the reserves data with Management and the independent
                  qualified reserves evaluator.

The Engineering, Environmental, Health and Safety Committee of the Board of
Directors has reviewed the Company's procedures for assembling and reporting
other information associated with oil and gas activities and has reviewed that
information with Management. The Board of Directors has, on the recommendation
of the Engineering, Environmental, Health and Safety Committee approved

         (f)      the content and filing with securities regulatory authorities
                  of the reserves data and other oil and gas information;

         (g)      the filing of the report of the independent qualified reserves
                  evaluator on the reserves data; and

         (h)      the content and filing of this report.


                                      -36-
<PAGE>

Because the reserves data are based on judgments regarding future events, actual
results will vary and the variations may be material.


(signed) "Ernie Sapieha"            (signed) "Murray Stodalka"
Ernie Sapieha                       Murray Stodalka
President & CEO                     Vice-President Operations and Engineering


(signed) "Jeffery Smith"            (signed) "Mel Belich"
Jeffery Smith                       Mel Belich
Chairman of the Engineering,        Chairman of the Board
Environmental, Health and
Safety Committee

May 19, 2004


                                      -37-
<PAGE>

                                   SCHEDULE C

                CHARTER OF THE AUDIT, RISK AND FINANCE COMMITTEE


MANDATE OF THE COMMITTEE

The mandate of the Audit, Finance and Risk Committee (the "COMMITTEE") of the
Board of Directors (the "BOARD") of Compton Petroleum Corporation (the
"COMPANY") is to oversee that management has applied due diligence in creating
and maintaining an effective risk management and control framework. This
framework should provide reasonable assurance that the financial, operational
and regulatory objectives of the Company are achieved and that the statutory
responsibilities of the Board are discharged. The Committee fulfils its role on
behalf of the Board, by overseeing:

1.       the integrity of the Company's financial statements, financial
         information and accounting, financial reporting (including MD&A, as
         hereinafter defined) and auditing processes;

2.       the external auditor's qualifications, independence and performance;

3.       the Company's compliance with legal and regulatory requirements; and

4.       risk management, management information systems, governmental
         legislation and external business of the Company.

While the Committee has the responsibilities and powers set forth in this
Charter, it is not the duty of the Committee to plan or conduct audits, to
determine that the Company's financial statements are complete, accurate and in
accordance with generally accepted accounting principles, or to certify the
Company's financial statements. Management is responsible for preparing the
Company's financial statements and the Company's external auditor is responsible
for auditing the annual financial statements and for reviewing the interim
financial statements. The Committee shall however, assist the Board in
overseeing that management and the external auditor fulfill their
responsibilities in the Company's financial reporting process.

It is not the duty of the Committee to conduct investigations to assure the
Company's compliance with laws, regulations, or the Company's Code of Business
Conduct and Ethics.

The Committee has the authority to obtain independent legal counsel and outside
accounting and other advisors as deemed appropriate to perform its duties and
responsibilities. The Company shall provide appropriate funding to compensate
the external auditor and any advisors that the Committee chooses to engage. The
Committee is authorized to communicate directly with the external auditor to
discuss and review specific issues as necessary.

The Committee will primarily fulfil its responsibilities by carrying out the
activities enumerated in the following sections of this Charter. The Committee
will report regularly to the Board regarding the execution of its duties and
responsibilities.

In fulfilling its mandate, the Committee shall:

(A)      INTERNAL AND DISCLOSURE CONTROLS

1.       review the effectiveness and integrity of the Company's system of
         disclosure controls and system of internal controls regarding finance,
         accounting, compliance and ethics, that management and the Board have
         established;

2.       where the Committee considers it necessary and appropriate, set up and
         review an internal audit process and review any appointment or
         dismissal of senior internal audit personnel appointed in connection
         therewith;


                                      -38-
<PAGE>

3.       review the evaluation of internal controls by the external auditor with
         management and the Company's subsequent follow-up to any identified
         weaknesses;

4.       review, in conjunction with the Governance and Compensation Committee
         of the Board, the appointment of the Chief Financial Officer;

5.       determine the appropriate resolution of conflicts of interest in
         respect of audit, finance and risk matters, properly directed to the
         Committee;

6.       review with management and the external auditor:

         (a)      in conjunction with the report of the external auditor, the
                  Company's audited annual financial statements, including
                  related footnotes and management's discussion and analysis of
                  financial conditions and results of operations ("MD&A"), and
                  quarterly financial statements,

         (b)      the significant accounting judgments and reporting principles,
                  practices and procedures applied by the Company in preparing
                  its financial statements including any newly adopted
                  accounting policies,

         (c)      significant changes to the audit plan, if any, and any serious
                  disputes or difficulties with management encountered during
                  the audit,

         (d)      the co-operation received by the external auditor during the
                  audit, including access to all requested records, data and
                  information,

         (e)      any correspondence with regulatory or governmental authorities
                  which raises material issues regarding the Company's financial
                  statements or accounting policies, and

         (f)      any other matters not described above that are required to be
                  communicated by the external auditors to the Committee
                  pursuant to applicable law and regulation;

7.       obtain an explanation from management of all significant variances
         between comparative reporting periods. The Committee shall review all
         financial statements prior to their presentation to the Board for
         approval;

8.       review and recommend for approval by the Board, all documents to be
         publicly disclosed, prior to their release, which contain audited or
         unaudited financial information. Such documents include any
         prospectuses, interim unaudited financial statements, year end audited
         financial statements, the annual report, the annual proxy circular, the
         annual information form, all press releases and disclosures made under
         MD&A;

9.       review with management the procedures that exist for the review of
         financial information extracted or derived from financial statements
         which is publicly disclosed by the Company other than in the documents
         listed in section 8 above and periodically, at least annually, assess
         the adequacy of those procedures, as required by Multilateral
         Instrument 52-110, section 2.3;

10.      review with management and the external auditor all off-balance sheet
         financing mechanisms being used by the Company, their risks and the
         clear disclosure of those risks and all other material financial risks
         to the Company's business;

11.      discuss with the Company's General Counsel, at least annually, legal
         and regulatory matters that may have a material impact on the financial
         statements;

12.      review with the Chief Financial Officer and the Chief Executive Officer
         of the Company their respective disclosures made to the Committee
         during the certification process as required by Multilateral Instrument
         52-109, including:


                                      -39-
<PAGE>

         (a)      any significant deficiencies or material weaknesses in the
                  design or operation of internal controls,

         (b)      any fraud involving management or other employees who have a
                  significant role in the Company's internal controls,

         (c)      any other obligations arising from certification, and

         (d)      any significant changes in the internal controls;

13.      review with management and the external auditor the Company's Code of
         Business Conduct and Ethics, and report to the Governance and
         Compensation Committee in respect thereof.

14.      establish and maintain procedures for:

         (a)      the receipt, retention and treatment of complaints received by
                  the Company regarding the Company's accounting, internal
                  accounting controls or auditing matters, and the confidential
                  and anonymous submission by Company employees of concerns

         (b)      the confidential and anonymous submission by Company employees
                  of concerns regarding questionable accounting or auditing
                  matters,

         and review all matters relating thereto; and

15.      review with management the details of all transactions between the
         Company and parties related to the Company;

(B)      OVERSIGHT OF THE EXTERNAL AUDITOR

1.       recommend to the Board and to the Shareholders the nomination of the
         external auditor, who shall be a "Registered Public Accounting Firm"
         within the meaning of applicable securities legislation, for the
         purpose of preparing or issuing an auditor's report or performing other
         audit, review or attestation services for the Company;

2.       review the qualifications and independence of the external auditor
         during the year;

3.       maintain a clear understanding with the external auditor that it is to
         have an open and transparent relationship with the Committee and that
         it is to report directly to the Committee;

4.       provide a scheduled opportunity to meet with the external auditor for
         full, frank and timely discussions of all material issues, without
         management present;

5.       discuss with the external auditor the scope and timing of the audit
         work with particular reference to high risk areas or areas of Board
         concern;

6.       inquire as to whether the audit partner receives compensation based on
         the audit partner procuring engagements to provide services other than
         audit, review or attest services to the Company;

7.       review all reportable events, including disagreements, unresolved
         issues and consultations, as defined in National Instruments 51-102 and
         31 (or its proposed successor National Instrument), on a routine basis,
         whether or not there is to be a change of external auditor;

8.       review all issues and documentation related to a change of external
         auditor, including information to be included in the Change of Auditor
         Notice and documentation called for under National Instruments 51-102
         and 31 (or its proposed successor National Instrument) and the planned
         steps for an orderly transition period;


                                      -40-
<PAGE>

9.       appropriately supervise and evaluate the performance of the external
         auditor and lead audit partner, and report conclusions to the Board;

10.      review and approve the Company's hiring policies regarding partners,
         employees, former partners and former employees of the current and
         previous external auditors of the Company;

11.      oversee the rotation of audit partners as required by applicable
         regulation and, in order to ensure continuing auditor independence,
         consider annually whether it is appropriate to adopt a policy of
         rotating the Company's external auditing firm on a regular basis;

12.      pre-approve the nature of, and fees for, all audit, review, attestation
         and significant non-audit services provided by the external auditor,
         prior to engagement, and disclose such pre-approvals in accordance with
         applicable securities law;

13.      consider the effect of significant non-audit engagements on the
         independence of the external auditor; and

14.      provide to the external auditor any information and explanations, and
         access to records, documents, books, accounts and vouchers of the
         Company that are, in the opinion of the external auditor, necessary to
         make the examinations and reports required under legislation or
         regulation;

(C)      OVERSIGHT OF FINANCIAL REPORTING AND ACCOUNTING POLICIES

1.       review with management and the external auditor significant financial
         reporting issues arising during the fiscal period and the methods of
         resolution;

2.       prior to the issuance of the external auditor's report on the Company's
         financial statements, discuss the following with the external auditor:

         (a)      all critical accounting policies and practices applied in the
                  financial statements,

         (b)      all alternative accounting and disclosure treatments of
                  financial information within generally accepted accounting
                  principles that have been discussed with management,
                  ramifications of the use of such alternate treatments and
                  disclosures, and the treatment preferred by the external
                  auditor, and

         (c)      other material written communications between the external
                  auditor and management, such as the post audit or management
                  letter and schedule of unadjusted differences;

3.       inquire of the external auditor as to the quality of the Company's
         accounting estimates, discussing significant judgments made in
         connection with the preparation of the financial statements;

4.       review with management any proposed changes in major accounting
         policies, the impact and clear disclosure of significant risks and
         uncertainties and key estimates and judgments of management that may be
         material to financial reporting;

5.       prepare such reports and letters or other disclosure documents as are
         required to be prepared by the Committee under applicable securities
         legislation; and

6.       review any notice received by the Committee with respect to an error or
         misstatement of which a director or officer becomes aware.

(D)      ADDITIONAL DUTIES AND RESPONSIBILITIES

1.       review the appointments of the Chief Financial Officer and any other
         key financial executives who are involved in the financial reporting
         process;


                                      -41-
<PAGE>

2.       review derivative and hedging policies of the Company and make
         recommendations to the Board in respect of gas contracts, hedging
         agreements and other similar financial transactions;

3.       review risk assessment and risk management policies. Such review should
         include the Company's major financial and accounting risk exposures,
         the steps management has undertaken to control them, and the clear
         disclosure of such material risks as part of the Company's continuous
         disclosure requirements; and

4.       review the amount and terms of any insurance to be obtained or
         maintained by the Company, including insurance with respect to
         potential liabilities incurred by the directors or officers in the
         discharge of their duties and responsibilities.

(E)      GENERAL

1.       The Committee shall review and assess annually the adequacy of this
         Charter and recommend any proposed changes to the Governance and
         Compensation Committee for approval.

2.       To fulfill its responsibilities and duties the Committee may:

         (a)      inspect any and all of the books, records and financial
                  affairs of the Company, its subsidiaries and affiliates; and

         (b)      meet with any executive or employee of the Company with or
                  without management to review such accounts, records and other
                  matters as any member of the Committee considers necessary and
                  appropriate.

3.       The Committee shall receive reports as required from the Governance and
         Compensation Committee and the Engineering, Environmental, Health and
         Safety Committee and discuss with them issues of relevance to the
         Committee.

4.       The Committee shall review when deemed necessary by the Committee any
         of the financial affairs of the Company, its subsidiaries or affiliates
         and make recommendations to the Board, to the external auditor, or to
         management, as appropriate.

5.       The Committee shall report regularly to the Board through the Chair of
         the Committee or through such other person appointed by the Committee
         the conclusions reached and issues considered by the Committee.

6.       The Committee shall perform any other activities consistent with this
         Charter as the Committee deems necessary or appropriate in order to
         carry out its mandate.

COMPOSITION  OF THE COMMITTEE

1.       The Committee shall be comprised of at least three directors.

2.       Each member of the Committee shall be an "independent", "outside", and
         "unrelated" (collectively, "INDEPENDENT") director, as affirmatively
         determined by the Board, which for purposes of this Charter shall mean:

                  (i)      a director who is not and has not been within the
                           previous three years an officer or employee or
                           material service provider of the Company and its
                           affiliates;

                  (ii)     a director who does not beneficially own 10% or more
                           of the outstanding voting securities of the Company;


                                      -42-
<PAGE>

                  (iii)    a director who is not a relative of the person set
                           out in (i) or (ii) residing in the same home as that
                           person;

                  (iv)     a director who is independent of management and is
                           free from any interest and any business or other
                           relationship which could, or could reasonably be
                           perceived to, materially interfere with the
                           director's ability to act with a view to the best
                           interests of the Company, other than interests and
                           relationships arising from shareholdings;

                  (v)      a director who has no direct or indirect material
                           relationship with the Company (a material
                           relationship is a relationship which could, in the
                           view of the Board, reasonably interfere with the
                           exercise of a directors independent judgment); and

                  (vi)     other than as a member of the Committee, a director
                           who does not and has not accepted any consulting,
                           advisorary or compensatory fee from the Company.

3.       At least half of the members of the Committee must be resident
         Canadians, as that term is defined in the BUSINESS CORPORATIONS ACT
         (Alberta).

4.       The Board shall appoint the members of the Committee at the first
         meeting of the Board following each annual meeting ("ANNUAL MEETING")
         of the shareholders of the Company.

5.       The Board shall appoint one member of the Committee to be the Chair of
         the Committee.

6.       A director appointed by the Board to the Committee shall be a member of
         the Committee until the next Annual Meeting or until his or her earlier
         resignation or removal by the Board. A member shall cease to be a
         member of the Committee upon ceasing to be a director of the Company.

7.       The Board may remove or replace any member of the Committee at any
         time.

8.       The Company's Corporate Secretary, or in his or her absence, one of the
         members chosen by the Committee shall be the Secretary of the
         Committee.

9.       Members of the Committee may not serve on the audit committee of more
         than two additional public companies without the prior approval of the
         Board.

10.      (a)      Each member of the Committee shall be financially literate. An
                  individual is financially literate if he or she has the
                  ability to read and understand a set of financial statements
                  that present a breadth and level of complexity of accounting
                  issues that are generally comparable to the breadth and
                  complexity of the issues that can reasonably be expected to be
                  raised by the Company's financial statements.

         (b)      A Committee member who is not financially literate may be
                  appointed to the Committee provided that the member becomes
                  financially literate within a reasonable period of time
                  following his or her appointment.

         (c)      At least one member of the Committee shall have accounting or
                  related financial management expertise and, where possible, at
                  least one member of the Committee


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<PAGE>

                  shall qualify as an "audit committee financial expert" within
                  the meaning of applicable securities legislation.


MEETINGS OF THE COMMITTEE

1.       The Committee shall convene at such times and places designated by the
         Chair of the Committee, at least on a quarterly basis, and whenever a
         meeting is requested by the Board, a member of the Committee, the
         external auditor, or a senior officer of the Company. The Committee
         shall meet in separate sessions with management and the external
         auditor at each regularly scheduled meeting.

2.       Notice of each meeting of the Committee shall be given to each member
         and to the external auditor, who shall be entitled to attend each
         meeting of the Committee.

3.       Notice of a meeting of the Committee shall:

         (a)      be in writing (which may be communicated by electronic
                  facsimile or other communication facilities);

         (b)      state the nature of the business to be transacted at the
                  meeting in reasonable detail;

         (c)      to the extent practicable, be accompanied by copies of
                  documentation to be considered at the meeting; and

         (d)      be given at least 24 hours preceding the time stipulated for
                  the meeting.

4.       A quorum for the transaction of business at a meeting of the Committee
         shall consist of a majority of the members of the Committee.

5.       A member of the Committee may participate in a meeting of the Committee
         by means of such telephonic, electronic or other communication
         facilities as permit all persons participating in the meeting to
         communicate adequately with each other. A member participating in such
         a meeting by any such means is deemed to be present at that meeting.

6.       In the absence of the Chair of the Committee, the members of the
         Committee shall choose one of the members present to be Chair of the
         meeting and, in the absence of the Secretary of the Committee, the
         members shall choose one of the persons present to be the Secretary of
         the meeting.

7.       Management of the Company may attend meetings of the Committee as
         deemed appropriate by the Committee, and shall attend meetings of the
         Committee when requested to do so by the Committee.

8.       Minutes shall be kept of all meetings of the Committee and shall be
         signed by the Chairman and Secretary of the meeting. The minutes shall
         be maintained with the Company's records, shall include copies of all
         resolutions passed at each meeting, and shall be available for review
         by members of the Committee, the Board, management and external
         auditor.




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