EXHIBIT 20.1
                                                                   ------------



                               [GRAPHIC OMITTED]
                     [LOGO - COMPTON PETROLEUM CORPORATION]




                            ANNUAL INFORMATION FORM
                      FOR THE YEAR ENDED DECEMBER 31, 2005

                         COMPTON PETROLEUM CORPORATION





                                 March 23, 2006


<PAGE>

                               TABLE OF CONTENTS

                                                                           PAGE

ABBREVIATIONS AND CONVERSION FACTORS.........................................2
DEFINITIONS..................................................................3
ADVISORIES...................................................................8
CORPORATE STRUCTURE..........................................................8
GENERAL DEVELOPMENT OF THE BUSINESS..........................................9
DESCRIPTION OF THE BUSINESS.................................................10
RISK FACTORS................................................................15
STATEMENT OF RESERVES DATA..................................................19
PRICING ASSUMPTIONS.........................................................23
RECONCILIATION OF CHANGES IN RESERVES AND FUTURE NET REVENUE................24
ADDITIONAL INFORMATION RELATING TO RESERVES DATA............................26
OTHER OIL AND GAS INFORMATION...............................................28
DIVIDENDS...................................................................33
CAPITAL STRUCTURE...........................................................33
MARKET FOR SECURITIES.......................................................34
CONFLICTS OF INTEREST.......................................................34
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.................34
MATERIAL CONTRACTS..........................................................35
INTERESTS OF EXPERTS........................................................35
RATINGS ....................................................................35
DIRECTORS AND OFFICERS......................................................36
AUDIT, FINANCE AND RISK COMMITTEE INFORMATION...............................38
COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE............................38
EXTERNAL AUDITOR FEES.......................................................38
TRANSFER AGENT AND REGISTRAR................................................39
ADDITIONAL INFORMATION......................................................39
SCHEDULE A..................................................................40
SCHEDULE B..................................................................42
SCHEDULE C..................................................................44


                                      -1-
<PAGE>

                      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;
"LT" means long ton;
"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;
"MLT" means thousands of long tons;
"MSTB" means thousand stock tank barrels; and
"NGLS" means natural gas liquids.


                                      -2-
<PAGE>

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
-------------------------------------------------------------------------------
      cubic feet                      cubic metres                    0.028174
      boe                             Mcfe                            6.000
      cubic metres of gas             cubic feet                     35.490
      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
-------------------------------------------------------------------------------


                                  DEFINITIONS

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; and

     (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" or "WE" 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.

"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.

"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.

                                      -3-
<PAGE>

"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,
           production storage tanks,  natural gas cycling and processing plants
           and central utility and waste disposal systems; and

     (d)   provide improved recovery systems.

"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.

"EUB" means the Alberta Energy and Utilities Board.

"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 defense 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
                                      -4-

<PAGE>

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
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 (such as Crown royalties)
           that are not deductible in computing taxable income;

     (c)   taking into account estimated tax credits and allowances; and

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

"FUTURE NET REVENUE" means the estimated net amount to be received with respect
to the development  and production of 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
           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.

"LIQUIDS" means crude oil, natural gas liquids and sulphur.

"NATURAL  GAS"  or  "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;

                                      -5-
<PAGE>

     (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
           of properties 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,  facilities and other costs of operating
and maintaining those wells and related equipment and facilities.

"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.

"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

     (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; and

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

"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.

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

"RESERVES" are estimated  remaining  quantities of oil, 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

                                      -6-
<PAGE>

accepted as being  reasonable  and shall be disclosed.  Reserves are classified
according to the degree of certainty associated with the estimates.

"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 geologically  directed  drilling effort,  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.

"UNDEVELOPED"  reserves are those reserves  expected to be recovered from known
accumulations  where a  significant  expenditure,  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.

"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.  Costs
of abandoning the gathering system or reclaiming the wellsite are not included.


                                      -7-
<PAGE>

                                   ADVISORIES
USE OF BOE EQUIVALENTS

The oil and natural gas  industry  commonly  expresses  production  volumes and
reserves  on a barrel of oil  equivalent  ("BOE")  basis  whereby  natural  gas
volumes are converted at the ratio of six thousand  cubic feet to one barrel of
oil. The intention is to sum oil, ngl, and natural gas  measurement  units into
one basis for  improved  measurement  of  results  and  comparisons  with other
industry  participants.  In several sections that follow,  Compton has used the
6:1  boe  measure  which  is the  approximate  energy  equivalency  of the  two
commodities  at the  burner  tip.  However,  boes  do  not  represent  a  value
equivalency  at the plant gate where Compton sells its  production  volumes and
therefore may be a misleading measure if used in isolation.


FORWARD LOOKING STATEMENTS

Certain information  regarding the Company contained herein constitutes forward
looking statements under the meaning of applicable  securities laws,  including
the  United  States  Private   Securities   Litigation   Reform  Act  of  1995.
Forward-looking statements include estimates,  plans,  expectations,  opinions,
forecasts,  projections,  guidance, or other statements that are not statements
of  fact,  including  statements  regarding  (i)  cash  flow,  2006  production
estimates, reserve estimates, capital expenditures,  2006 drilling program, tax
estimates,  total  future net revenue,  pricing  assumptions,  abandonment  and
reclamation  costs, and (ii) other risks and uncertainties  described from time
to time in the reports and filings made by Compton with  securities  regulatory
authorities.  Although Compton believes that the expectations reflected in such
forward looking  statements are reasonable,  it can give no assurance that such
expectations will prove to have been correct. There are many factors that could
cause  forward  looking  statements  not to be  correct,  including  risks  and
uncertainties  inherent in the Company business.  These risks include,  but are
not limited  to:  crude oil and natural  gas price  volatility,  exchange  rate
fluctuations,  availability  of services and  supplies,  operating  hazards and
mechanical  failures,  uncertainties  in  the  estimates  of  reserves  and  in
projection   of  future  rates  of   production   and  timing  of   development
expenditures,  general  economic  conditions,  and the actions or  inactions of
third-party operators,  and other risks set forth in the "Risk Factors" section
of this Annual  Information Form.  Compton may, as considered  necessary in the
circumstances,  update or revise  forward  looking  information,  whether  as a
result of new information,  future events, or otherwise.  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.  Compton  Petroleum  Corporation  and Hornet
Energy Ltd, a wholly-owned subsidiary of Compton Petroleum Finance Corporation,
are the partners of the partnership.  The majority of our production activities
are carried out through this partnership.

Compton Petroleum Finance  Corporation,  formed under the laws of Alberta, is a
wholly-owned  subsidiary of Compton  Petroleum  Corporation.  Compton Petroleum
Finance  Corporation  has no  independent  operations  and  has no  significant
liabilities  or assets other than US$300  million of 7 5/8% Senior  Notes,  its
equity interest in Hornet Energy

                                      -8-
<PAGE>

Ltd.  and  intercorporate  indebtedness.   The  registered  office  of  Compton
Petroleum Finance Corporation is 4300 Bankers Hall West, 888 - 3rd Street S.W.,
Calgary, Alberta, Canada, T2P 5C5.

Compton Petroleum Holdings Corporation,  formed under the laws of Alberta, is a
wholly-owned  subsidiary of Compton  Petroleum  Corporation.  Compton Petroleum
Holdings  Corporation  has no  independent  operations  and has no  significant
liabilities  or assets  other than owning  US$158,250,000  aggregate  principal
amount of 9.90% Notes and intercorporate indebtedness. The registered office of
Compton  Petroleum  Holdings  Corporation  is 4300 Bankers Hall West, 888 - 3rd
Street S.W., Calgary, Alberta, Canada, T2P 5C5.

                   [GRAPHIC OMITTED -- ORGANIZATIONAL CHART]

                        -----------------------------
        100% ---------- Compton Petroleum Corporation ----------- 96%
         |              -----------------------------             |
         |                             |                          |
         |                            100%                        |
         |                             |                          |
--------------------      -------------------------       -----------------
Compton Petroleum         Compton Petroleum Finance       Compton Petroleum
Holdings Corporation             Corporation                 (partnership)
--------------------      -------------------------       -----------------
                                       |                          |
                                      100%                        4%
                                       |                          |
                              ------------------                  |
                              Hornet Energy Ltd.  ----------------
                              ------------------

The consolidated  financial  statements include the accounts of the Company and
all of its subsidiaries and partnerships.


                      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 Canada Sedimentary Basin (the "WCSB") in Canada.  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.  Compton's shares are listed
on the Toronto  Stock  Exchange  under the symbol CMT and on the New York Stock
Exchange under the symbol CMZ.

THREE YEAR HISTORY

In 2003, Compton focused on the resolution of pipeline and facility constraints
in its Southern Alberta core area. The Mazeppa Processing Partnership, which is
not  affiliated  with  Compton,  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 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  was then able to continue to
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  in  2003.  Compton's  capital  program  totaled  $285  million,
including the consolidation of the Mazeppa gas plant expenditures.  The Company
drilled 168 gross (134 net) wells in 2003 with an 83% success rate.

In 2004,  the  expansion  of the Mazeppa gas plant from 90 MMcf/d to 135 MMcf/d
through  the  addition  of 45  MMcf/d  of sweet  gas  processing  capacity  was
completed.  This expanded Compton's  processing capacity in Southern Alberta to
200 MMcf/d and removed all  restrictions.  The Mazeppa  Processing  Partnership
completed the $75 million external financing of the acquisition, expansion, and
operations of the Mazeppa facilities and repaid funds borrowed from Compton.

                                      -9-
<PAGE>

Consolidated  capital  expenditures  totaled  $316  million in 2004 and Compton
drilled  186 gross  (146  net)  wells  with a 90%  success  rate.  Of the wells
drilled,  77% were  classified as development  wells and 23% were classified as
exploratory  wells.  Approximately  26 MMBoe was added to the Company's  proved
plus  probable   reserves  through  drilling   successes,   acquisitions,   and
extensions.  Total proved plus probable  reserves  increased 22% from the prior
year to 145 MMBoe.

In  2005,  progress  was  made on each of the  Company's  five  resource  plays
including the Edmonton  Horseshoe Canyon coalbed  methane,  plains Belly River,
Basal  Quartz  at  Hooker  and  thrusted,  foothills  Belly  River at Callum in
Southern Alberta,  and the Rock Creek/Gething play at Niton in Central Alberta.
Compton was one of the top 10 most active  operators in Canada  throughout  the
year.  The Company's  consolidated  capital  program of $513 million,  included
drilling  392 gross (334 net)  wells  with a 96%  success  rate.  The  drilling
program  resulted  in an exit  production  rate of  35,500  boe/d  and  average
production of 29,424 boe/d for the year.  High  commodity  prices and increased
production generated record revenue of $558 million.

Compton's  proved plus probable  reserves  totaled 207 MMBoe as at December 31,
2005.  Approximately  62 MMBoe was added to the Company's  proved plus probable
reserves through drilling successes, acquisitions, and extensions.


                          DESCRIPTION OF THE BUSINESS

EXPLORATION AND PRODUCTION OPERATIONS

Compton's exploration, development and exploitation activities are concentrated
principally in three core areas: 1) Southern Alberta targeting the plains Belly
River,  Edmonton Horseshoe Canyon coalbed methane ("CBM"),  Hooker Basal Quartz
and thrusted, foothills Belly River at Callum; 2) Central Alberta targeting the
Gething/Rock  Creek at Niton;  and 3) the Peace River Arch area  producing from
the Charlie Lake pool at Cecil/Worsley. 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.

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 is implementing this objective by
focusing on the efficient  exploration,  development  and  exploitation of ithe
Company's 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 AREAS.  Compton is focused on its core areas, which provide
a balanced portfolio of exploration,  development,  and exploitation prospects.
These areas are the geographic focus of the Company's  seismic database rights,
and are  areas  in  which  Management  and  staff  have  significant  technical
expertise and operational  experience.  Compton intends to generate exploration
opportunities  and to increase the Company's  undeveloped  land base within the
WCSB.

FOCUS ON UNCONVENTIONAL NATURAL GAS IN LARGE RESOURCE PLAYS. As of December 31,
2005,  73% of  proved  reserves  were  natural  gas.  The  Company  has  gained
considerable  technical expertise and achieved significant success in exploring
for unconventional, larger natural gas accumulations in the WCSB. Compton plans
to  continue  to focus on finding  and  developing  these  types of natural gas
opportunities  because  of their  generally  lower  decline  curves  and higher
economic return over the life of the reserves compared to conventional  natural
gas opportunities.  The large scale nature of the Company's resource plays also
offers  multiple  low-risk  drilling  locations  resulting  in lower  costs and
decreased exploration risk.

                                     -10-
<PAGE>

PURSUE GROWTH  THROUGH THE DRILL BIT  COMPLEMENTED  BY SELECTIVE  ACQUISITIONS.
Compton plans to continue to reinvest internally generated cash flow and to use
other  sources of capital to fund the growth of the Company's  exploration  and
development  programs  and to further  increase  its  undeveloped  land base to
maintain a growing  inventory  of drilling  prospects  in core areas.  In 2004,
Compton began an  accelerated  drilling  program.  Based on plans for an annual
drilling  program of 500 to 700 gross wells,  the Company has over ten years of
drilling  inventory on existing lands. Most of these planned wells are expected
to be in close proximity to producing  wells in existing core areas.  Compton's
drilling  success  rate  has been at or  above  90% for each of the past  three
years,  providing  confidence in the  Company's  ability to  successfully  grow
reserves and production from its extensive inventory of drilling locations.

CONTROL  INFRASTRUCTURE  AND  OPERATORSHIP.  Compton believes that control over
gathering and processing  infrastructure  and operatorship of drilling programs
will  continue  to be  critical  to the  success  of the  Company's  full-cycle
exploration  program.   Compton  currently  owns  or  has  access  to  critical
infrastructure  in each of its three  core  areas.  Being an  operator  ensures
discretion in determining  the timing and  methodology of ongoing  exploration,
development,  and exploitation programs.  Compton expects to continue to expand
its working interest in core areas to maximize these operating efficiencies.

MAINTAIN  FINANCIAL  FLEXIBILITY.  The  Company  is  committed  to  maintaining
financial  flexibility   sufficient  to  allow  it  to  pursue  its  full-cycle
exploration  program  in  periods  of low  commodity  prices  and to respond to
opportunities   for  strategic   acquisitions   as  they  arise.   Compton  has
historically  funded its exploration,  development,  and  exploitation  capital
program through  internally  generated cash flow and has financed  acquisitions
through bank debt, the issuance of common shares, or a combination thereof. The
Company's  accelerated drilling program has recently been, and will continue to
be, funded through  internally  generated cash flow, the issuance of additional
equity and debt, and non-core  property  sales.  Other  components of Compton's
financial  discipline  include  establishing  appropriate  leverage  ratios and
maintaining an active commodity hedging program.

PRINCIPAL PROPERTIES

SOUTHERN ALBERTA

Southern Alberta remains the primary focus of Compton's activities. The Company
holds 804,007  (699,751 net) acres of land in the South,  which are prospective
for multiple zones  including  Basal Quartz at Hooker,  thrusted Belly River at
Callum,  Wabamun/Crossfield,  Plains Belly River,  and  Edmonton/CBM.  In 2005,
Compton  drilled  195 (183 net) wells in  Southern  Alberta  with a 99% success
rate. The Company  anticipates  spending $361 million and drilling 277 wells in
the area in 2006.

HOOKER BASAL QUARTZ

During the past year, Compton continued the development of its Lower Cretaceous
Basal Quartz  resource  play at Hooker.  The play covers an  extensive  area of
260,270  (195,200 net) acres. In 2005, the Company drilled 27 wells,  extending
the productive limits and optimizing reserve recovery in the heart of the pool.

In 2005,  Compton designed and completed several advanced core and log analysis
studies to gain a better understanding of the petrophysical  characteristics of
the play. As a result of this work,  the Company now estimates  that the Hooker
pool contains at least 1.5 TCF of gas-in-place. Compton is currently conducting
further engineering and geological studies to confirm its expectations that the
gas-in-place  may be greater  than  initially  determined.  It has also  become
evident that the edges of the Hooker pool are not yet clearly identified and as
such,  Compton has designed its 2006 drilling  program to infill and extend the
productive limits of the pool.

The Hooker play is currently drilled on one to two wells per section,  however,
engineering  models and geological  studies  indicate that at least three wells
per  section  will be  required  to  maximize  reserve  recovery  from this low
permeability gas pool.  Compton has made an application to the EUB to conduct a
pilot   drilling   program  on  two  sections  in  the  pool  to  evaluate  the
effectiveness of reduced spacing.

                                     -11-
<PAGE>

PLAINS BELLY RIVER AND HORSESHOE CANYON COALBED METHANE

In 2005, the Company drilled 170 Belly River wells in the Centron,  Gladys, and
Brant  areas,  with all wells  encountering  multiple  pay  sections and uphole
producible  Edmonton/Horseshoe  Canyon Coals.  The Belly River drilling program
continues to exceed expectations.

Compton  further  refined its Belly River seismic and geological  models during
the year.  The use of the  Company's  extensive 3D and 2D seismic  database was
critical to identifying the best producible  sands.  The models were tested and
confirmed through drilling.

Compton  currently  has  approval  to drill  two  wells  per  section  on seven
townships of land. The Alberta Energy and Utilities Board recently  announced a
phased  modification to spacing for the Belly River in Southern Alberta that is
intended to see the standard  spacing  change from one well per section to four
wells per section. This initiative would effectively double the number of Belly
River drilling locations in the Company's inventory. In anticipation of reduced
spacing approval,  Compton initiated three 3D seismic programs to assist in the
identification  of  downspace  locations.  Drilling in select  areas on reduced
spacing is expected to start during the third quarter of 2006.  This will allow
Compton to  dramatically  ramp up its Belly  River/Edmonton  drilling  program,
commencing in 2007.

Compton will also define the optimum  development  of the  vertical  section of
Belly River and Edmonton Horseshoe Canyon zones. The Company plans to drill 250
wells in 2006 that will have the  potential to be  completed in both zones.  In
addition,  Compton has drilled over 400 wells  through the  Edmonton  Horseshoe
Canyon  formation  into the Belly  River  sands and the  Company is planning to
re-complete 70 of these wells in the Edmonton in 2006.

Compton holds 664,175  (597,760 net) acres of land in Southern  Alberta that is
prospective  for  dry  Edmonton   Horseshoe  Canyon  coalbed  methane  and  the
underlying  Plains Belly River sands.  During 2005,  Compton  drilled and cored
four CBM pilots  across its Southern  Alberta  acreage to gather the  necessary
geological evidence to better quantify its CBM resource  potential.  Each pilot
consisted of four to six wells,  for a total of 19 wells drilled.  In-line flow
testing on the initial  pilots  commenced in the first  quarter of 2006 and two
additional pilots are in various stages of well licensing.

The  pilots  assessed  the  potential  of  483,560  (435,200  net) acres of the
Company's lands in the South. Compton worked closely with Netherland,  Sewell &
Associates,   Inc.,   ("Netherland  Sewell")  independent  reserve  evaluators,
throughout  the pilot  programs to quantify the resource  potential  associated
with the Horseshoe Canyon coals.  Netherland Sewell has determined the original
unrisked  gas-in-place in the Horseshoe Canyon coals to be 3.05 Tcf and Compton
estimates the net original unrisked gas-in-place on the Company's acreage to be
2.7 Tcf. This  gas-in-place  number is  restricted  to the coals only,  with no
interbedded Edmonton sands, silts, or shales included.  Additionally, the pilot
evaluations  excluded any  potential  gas that may be present in the  overlying
Scollard Formation.

As  confirmed  by well  logs,  the  remaining  177,780  (160,000  net) acres of
Compton's  acreage contain  Edmonton sands,  silts, and Horseshoe Canyon coals,
and will require further core confirmation of the gas content. In 2006, Compton
will evaluate and quantify the potential of the Edmonton sands and silts across
the Company's acreage in 2006.

The Company has production from the Edmonton Horseshoe Canyon coals at Centron,
Gladys,  Brant, and Ghost Pine. Currently Belly River production extends across
Compton's Southern Alberta lands.

CALLUM THRUSTED BELLY RIVER

The Callum property  consists of a series of low  permeability,  overpressured,
thrusted  Upper  Cretaceous  Belly  River  sands in the  foothills  of Southern
Alberta.  Subsequent to year end, the Company  acquired its  partner's  working
interest in the play and now holds a 100% interest in 70,400 acres of land.

                                     -12-
<PAGE>

In the second  quarter of 2005,  the Company  drilled a 100%  working  interest
natural gas well at Callum.  Specialized core analysis  techniques were used to
assist in identifying  more  prospective  intervals and to optimize  completion
fluids and frac design  parameters.  The  lowermost  sand in the stacked  Belly
River  sequence  was  completed  in this well and Compton  plans to monitor and
analyze  this single zone  performance  before  completing  prospective  uphole
zones. The well was placed on continuous production in December 2005. The first
two weeks of initial production averaged approximately 1,525 boe per day from a
single sand and the well is continuing to produce approximately 300 boe per day
as at the end of  February  2006.  This  well has  significantly  improved  the
Company's  geological,  geophysical,  and  engineering  models of the play. The
resultant  advances in the  understanding of this complex reservoir are a major
step forward in the development of the Callum play.

The play is  technically  complex and the key to  successfully  developing  the
Callum prospect rests with rock  characterization and completion  optimization.
In the eight Compton wells drilled to date, various completion  techniques have
been evaluated.  All wells have produced gas and initial production ranged from
300 Mcfe/d to 8 MMcfe/d.

A second well was drilled in December 2005,  encountering  multiple sands.  The
well has since been cased and  Compton is  currently  testing.  The second well
will be completed  using methods  pioneered by Compton on its previous well. In
2006, 10 wells are planned at Callum.

Based on Compton's initial detailed  geological,  geophysical,  and engineering
analysis of seismic, cores, well logs, test and production data, Callum appears
to exhibit many similarities to the deep  unconventional gas pools of the Rocky
Mountain  region of the United States,  specifically in the Greater Green River
Basin in Wyoming.

CENTRAL ALBERTA

Central  Alberta  provides  Compton with excellent  exploration and development
drilling  opportunities using analogous  techniques gained through its years of
experience in Southern Alberta  unconventional gas development.  Compton has an
average 55% working  interest in 541,643  (297,475 net) acres of land. In 2005,
the  Company  drilled 73 (38 net) wells  with a 97%  success  rate and plans to
drill 90 wells in the area in 2006.

NITON

The Niton area,  where the majority of Compton's  Central Alberta acreage lies,
is characterized by multi-zone, deep basin targets analogous to the Hooker pool
in Southern Alberta. The Company has an interest in 137,390 (103,040 net) acres
of land in the play targeting the Gething and Rock Creek  formations.  In 2005,
33 wells were drilled and results have continued to exceed expectations.

As a result of the Company's  successful drilling program at Niton, the Compton
owned McLeod River gas plant will be operating at maximum capacity of 20 MMcf/d
in the first half of 2006. The Company is currently  evaluating plant expansion
alternatives,  as well as the option of routing a portion of its  production to
adjacent  non-operated  plants,  in  which  the  Company  holds  minor  working
interests.

PEACE RIVER ARCH

The Peace River Arch area, located north of Grande Prairie, contains multi-zone
exploration  and development  opportunities.  This area includes both light oil
production at  Cecil/Worsley  and natural gas  exploration  at Howard and Pouce
Coupe.  The Company  averages a 61% working  interest in 199,040  (121,634 net)
acres of land in the area. In 2005,  Compton drilled 124 (114 net) wells in the
Arch with an 89% success rate and plans to drill 106 wells in 2006.

CECIL/WORSLEY

Compton's   2005  drilling   program  at  Worsley  was  extremely   successful,
significantly  increasing the reserve value and  production  from the area. The
Company drilled 80 Charlie Lake oil wells,  more than twice the original number
budgeted, which resulted in pool boundary extensions in all directions.

                                     -13-
<PAGE>

Approval for a pool wide waterflood on the Charlie Lake H and J pool at Worsley
was received in February 2005 and a total of eight wells have been converted to
injectors  thus far.  The  waterflood  is  projected  to increase  the ultimate
recovery factor for the pool to 25% from 15% on primary depletion.  The Company
will continue its program at Worsley in 2006 and anticipates  drilling 90 wells
in the upcoming year.

At Cecil,  23 100% working  interest and 9  non-operated  40% working  interest
horizontal  Charlie Lake oil wells were drilled in 2005. All wells  encountered
excellent  pay  zones  and  have  been  systematically  brought  on  production
throughout  2005 and into the first  quarter of 2006.  Compton  is  undertaking
geological and engineering work to evaluate additional  waterflood potential in
the Cecil  area.  The  Company  plans to drill 17 wells in 2006 and to focus on
optimizing production from its previously drilled horizontal wells.

PRINCIPAL MARKETS AND DISTRIBUTION METHODS

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  10% of the Company's  natural gas production in 2005
was  committed  to  aggregators,  compared  to an average  of 11% in 2004.  The
average  aggregator  price  realized  in  2005  was  $1.25/Mcf  less  than  the
non-aggregator  prices  realized  during the year.  Natural gas  production  is
transported  through  regulated  pipelines  within Alberta,  at tolls requiring
government approval.

The Company's crude oil sales are priced at Edmonton postings and are typically
sold on 30 day  evergreen  arrangements.  Natural gas liquids are bid out on an
annual basis to obtain the most favorable pricing.  The Company sells crude oil
and natural gas liquids  primarily to refineries and marketers of crude oil and
natural gas liquids.  Liquids may be transported through regulated pipelines or
trucked to the point of sale.

ENVIRONMENTAL POLICIES

Compton believes in the importance of protecting the  environment.  The Company
is committed  to  conducting  all  operations  in a safe manner that  minimizes
environmental  impact,  while  meeting  regulatory  requirements  and corporate
standards. The Company maintains a comprehensive range of internal programs and
controls to promote  regulatory  compliance and an appropriate  level of safety
and  environmental  protection across its operations.  The Company's  proactive
program includes annual environmental  compliance audit and inspection programs
to ensure Compton's facilities continually meet or exceed regulatory standards.
The Company has participated in programs for continual improvement set forth by
the Canadian Association of Petroleum  Producers,  Alberta Energy and Utilities
Board, Alberta Environmental Protection,  and other related associations,  thus
demonstrating  Compton's  commitment to minimizing the Company's  environmental
impact.

The  Company  carries  out its  activities  in  compliance  with  all  relevant
regulations and industry best practices.  At present, the Company believes that
it meets all existing environmental  standards and regulations and has included
appropriate  amounts in its  capital  expenditure  budget to  continue  to meet
current environmental protection requirements.  The Company does not anticipate
making extraordinary material expenditures for environmental  compliance during
2006.  However, it does expect to incur site restoration costs over a prolonged
period as existing  wells become fully  produced.  Compton  provides for future
abandonment  and  reclamation  costs in its financial  statements in accordance
with Canadian generally accepted accounting principles.

MAZEPPA PROCESSING PARTNERSHIP

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.  Compton
does not have an ownership  position in MPP.  Through a  management  agreement,
Compton  manages the  activities  of MPP and is therefore  considered to be the
primary beneficiary of MPP's operations.  As a result, Compton consolidates the
accounts of MPP for reporting purposes in accordance with the guidelines issued
by  the  Accounting   Standards   Board,   in  Accounting   Guideline   AcG-15,
"Consolidation  of Variable  Interest  Entities."  The results of the midstream
activities are immaterial to Compton's consolidated financial condition.

                                     -14-
<PAGE>

EMPLOYEES

As at December 31,  2005,  Compton had 155  full-time  employees in its Calgary
office and 43 full-time employees at field locations.

COMPETITIVE CONDITIONS

Producers  benefited from high oil and gas prices in 2005,  increasing  revenue
and cash flow.  However,  higher  commodity  prices  also  accelerated  capital
programs throughout the industry, resulting in service and supply shortages and
increasing the overall cost of doing business.  As commodity prices weakened in
the first few months of 2006 due to unseasonably  warm weather and concern over
the high natural gas storage levels, field and operating netbacks decreased.

Land prices continue to climb, adding considerably to finding, development, and
acquisition  ("FD&A")  costs,  as well as consuming a larger  portion of annual
budgets.  In Compton's  core areas,  prices at recent land sales are up to four
times what the Company originally paid for its undeveloped acreage.

Drilling  rigs,  service rigs,  equipment,  and  experienced  crews continue to
operate at or near maximum capacity, which results in escalating drilling costs
and inefficiencies.  Deeper drilling and more complex plays have contributed to
higher FD&A costs for the industry in general.  Strong  demand for  experienced
professionals  has caused a  significant  increase in salaries  and  workloads,
further adding to  inefficiency in the industry.  Additionally,  the increasing
complexity and ever changing  government rules regarding license  applications,
environmental  regulations,  and governance matters is adding  significantly to
overall cost and time required to complete operations.

The mergers and  acquisitions  ("M&A")  market in 2005 was quite  strong and it
appears the high level of  activity  will  continue in 2006.  The M&A market is
being driven by several factors. High commodity prices and the belief they will
stay high are raising the value of oil and gas producers in the equity  market,
while  large  amounts of  available  cash in  combination  with rising FD&A are
encouraging producers to seek growth through acquisitions.


                                  RISK FACTORS

VOLATILITY OF PRICES, MARKETS AND MARKETING PRODUCTION

Oil and gas prices  have  historically  been  extremely  volatile.  The average
prices that the Company currently receives for its production are significantly
higher than historic  averages.  Factors which  contribute to oil and gas price
fluctuations  include global demand,  domestic and foreign  supplies of oil and
gas, the price of foreign oil and gas imports, decisions of the Organization of
Petroleum Exporting  Countries relating to export quotas,  domestic and foreign
governmental regulations, political conditions in producing regions, global and
domestic economic conditions,  the price and availability of alternative fuels,
including liquefied natural gas, and weather conditions.

The Company's  financial  condition is  substantially  dependent on, and highly
sensitive  to, oil and gas  commodity  prices.  Any material  decline in prices
could result in a material reduction of Compton's  operating results,  revenue,
reserves,  and overall value. Lower commodity prices could change the economics
of  production  from some wells.  As a result,  the Company  could elect not to
drill, develop, or produce from certain wells. In addition, Compton is impacted
by the  differential  between prices paid by refiners for light quality oil and
the grades of oil produced by the Company.

Under Canadian GAAP, oil and gas assets are reviewed  quarterly to determine if
the carrying value of the assets  exceeds their  expected  future cash flows. A
sustained  period of low commodity prices may reduce expected future cash flows
and  require  a write  down to the  fair  value  of the  Company's  oil and gas
properties, thereby adversely affecting operating results.

Any future and  sustained  period of weakness in oil and gas prices  would also
have an adverse effect on the Compton's capacity to borrow funds. The Company's
senior secured credit  facilities,  as the borrowing  amount  determined by the
lenders,  is based on  their  estimate  of the  value of the  Company's  proved
reserves.  A reduction in the  quantity or value of reserves may also  obligate
Compton to make additional payments under the processing agreement with MPP.

                                     -15-
<PAGE>

Any decline in the Company's ability to market production could have a material
adverse  effect  on  production  levels  or on  the  sale  price  received  for
production.  Compton's  ability  to market  the oil and gas from the  Company's
wells depends on numerous factors beyond the Company's  control,  including the
availability  and capacity of gas gathering  systems,  pipelines and processing
facilities,  and their proximity to the wells.  The Company will be impacted by
Canadian  federal and  provincial,  as well as U.S.  federal and state,  energy
policies,  taxes,  regulation  of  oil  and  gas  production,  processing,  and
transportation,  as well as Canadian federal  regulation of oil and gas sold or
transported outside of the province of Alberta.

NEED TO REPLACE RESERVES

Compton's future success depends upon the Company's  ability to find,  develop,
or acquire  additional oil and gas reserves that are economically  recoverable.
Without  successful  exploration,  development,  exploitation,  or  acquisition
activities,  the Company's reserves will deplete and, as a consequence,  either
production or the average life of reserves will decline.  If future  production
declines  to the extent that cash flow  becomes  insufficient  to fund  capital
expenditures,  and external  sources of capital become limited or  unavailable,
the Company's  ability to make the necessary  capital  expenditures to maintain
and expand its oil and gas reserves will be impaired.  Compton cannot guarantee
that  the  Company  will be able to find  and  develop  or  acquire  additional
reserves at an acceptable cost.

Management will continue to evaluate  prospects on an ongoing basis in a manner
consistent with industry standards and past practices. The long term commercial
success of the Company depends on its ability to find,  acquire,  develop,  and
commercially  produce  oil and gas  reserves.  No  assurance  can be given that
Compton  will be able to locate  satisfactory  properties  for  acquisition  or
participation. Moreover, if such acquisitions or participations are identified,
the Company may  determine  that  current  markets,  terms of  acquisition  and
participation,  or pricing  conditions make such acquisitions or participations
uneconomic.

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  acquisitions to complement  existing activities while striving for a
balance  between  exploration  and  lower  risk  development  and  exploitation
prospects.

UNCERTAINTY OF RESERVE ESTIMATES

Estimates  of oil and gas  reserves  and the  future  net cash flow  therefrom,
involve a great deal of uncertainty because they depend upon the reliability of
available  geologic  and  engineering  data,  which  is  inherently  imprecise.
Geologic and engineering data are used to determine the probability that an oil
and gas reservoir exists at a particular location,  and whether oil and gas are
recoverable   from  the  reservoir.   The  probability  of  the  existence  and
recoverability  of reserves is less than 100% and actual  recoveries  of proved
reserves may be materially different from estimates.

Estimates  of oil and gas reserves  require  numerous  assumptions  relating to
operating conditions and economic factors, including future oil and gas prices,
recovery costs, the availability of enhanced recovery  techniques,  the ability
to market production,  and governmental and other regulatory  factors,  such as
taxes,  royalty rates, and environmental laws. A change in one or more of these
factors could result in known quantities of oil and gas previously estimated as
proved  reserves  becoming  unrecoverable.  Each of these  factors  also impact
recovery costs and  production  rates,  and therefore,  will reduce the present
value of future net cash flows from estimated reserves.

In  addition,  estimates  of  reserves  and  future  net  cash  flows  expected
therefrom,  that are prepared by different independent engineers or by the same
engineers at different times, may vary substantially.


EXPLORATION, DEVELOPMENT AND PRODUCTION RISKS

There  are  many  operating  risks  and  hazards  inherent  in  exploring  for,
producing,  processing,  and transporting oil and gas. Drilling  operations may
encounter  unexpected  formations  or  pressures  that  could  cause  damage to
equipment or personal injury and fires,  explosions,  blowouts,  oil spills, or
other accidents may occur. Additionally,

                                     -16-
<PAGE>

Compton  could  experience  interruptions  to or the  termination  of drilling,
production,  processing,  and  transportation  activities  due to bad  weather,
natural  disasters,  delays in  obtaining  governmental  approvals or consents,
insufficient  storage  or  transportation  capacity,  or other  geological  and
mechanical conditions.  Any of these events resulting in a shutdown or slowdown
of operations,  will adversely affect the Company's business.  While close well
supervision and effective  maintenance  operations can contribute to maximizing
production  rates over time,  production  delays and declines from normal field
operating  conditions  cannot be  eliminated  and can be expected to  adversely
affect revenue and cash flow levels to varying degrees.

Drilling  activities,  including  completions,  are subject to the risk that no
commercially productive reservoirs will be encountered and the Company will not
recover all or any portion of its investment. The cost of drilling, completing,
and operating wells is often  uncertain due to drilling in unknown  formations,
the costs associated with encountering various drilling conditions such as over
pressured  zones,  and changes in drilling  plans and  locations as a result of
prior exploratory wells or additional seismic data and interpretations thereof.

INSURANCE

The risks and hazards of  Compton's  operations  could  result in damage to, or
destruction  of,  oil and gas  wells,  production  and  processing  facilities,
pipelines or other property, environmental damage, or personal injury for which
the Company will be liable.  The location of operations  near populated  areas,
including residential areas,  commercial business centers, and industrial sites
could  increase  these risks and  hazards.  The Company  cannot  fully  protect
against all of these risks, nor are all of these risks  insurable.  Compton may
become  liable for damages  arising from these events  against  which it cannot
insure or  against  which it may elect not to insure  because  of high  premium
costs or other reasons. The occurrence of a significant event not fully insured
or indemnified  against could seriously harm Compton's  financial condition and
operating results.

COMPETITION

The oil and gas  industry  is highly  competitive.  The  Company  competes  for
capital, acquisitions of reserves, undeveloped lands, skilled personnel, access
to  drilling  rigs,  service  rigs and other  equipment,  access to  processing
facilities,  and pipeline and refining  capacity with a  substantial  number of
other  organizations,  many of which may have greater  technical  and financial
resources  than  Compton.  Some of these  organizations  not only  explore for,
develop  and  produce  oil and gas but also carry on  refining  operations  and
market crude oil and other products on a worldwide  basis. As a result of these
complementary  activities,  some  competitors may have greater and more diverse
competitive resources to draw on than Compton does.

AVAILABILITY OF DRILLING EQUIPMENT AND ACCESS RESTRICTIONS

Compton's drilling  operations could be curtailed,  delayed,  or cancelled as a
result of access  restrictions  or  shortages  or  delays  in the  delivery  of
equipment  and  services.  Oil and gas  industry  operations  in the  WCSB  are
affected by road bans imposed from time to time,  which can restrict  access to
well sites and production facility sites. In addition, landowner constraints or
poor surface  conditions  could  disrupt  access to the  Company's  properties.
Compton's  inability to access the Company's  properties or to conduct business
as planned could result in a shutdown or slowdown of operations.

Exploration  and  development  activities  also depend on the  availability  of
drilling and related  equipment in the particular  areas where such  activities
will be  conducted.  Increased  demand for that  equipment  or  imposed  access
restrictions  may affect the  availability  of equipment to the Company and may
delay exploration and development activities.

ADDITIONAL FUNDING REQUIREMENTS

Compton's  ongoing  activities  may not  generate  sufficient  cash  flow  from
operations to fund future exploration,  development,  or acquisition  programs.
The Company may require  additional  funding and there can be no assurance that
debt or  equity  financing  will  be  available  or  sufficient  to meet  these
requirements  or that it will be on  acceptable  terms.  Failure to obtain such
financing on a timely basis could cause Compton to forfeit interests in certain
properties,  miss certain  acquisition  opportunities,  and reduce or terminate
operations. This may result in the

                                     -17-
<PAGE>

Company not being able to replaces its reserves or maintain  production,  which
will have an adverse effect on its financial position.

RELIANCE ON KEY EMPLOYEES

Compton depends to a large extent on the services of key management  personnel,
including the Company's executive officers and other key employees, the loss of
any of whom could have a material  adverse  effect on  operations.  The Company
does not  maintain  key man  life  insurance  with  respect  to any  employees.
Compton's  success will be dependent upon its ability to continue to employ and
retain skilled personnel.

ENVIRONMENTAL RISKS

The oil and gas  industry  is  subject  to  extensive  environmental  laws  and
regulations   pursuant  to  local,   provincial,   and   federal   legislation.
Environmental  regulation  provides for, among other things,  restrictions  and
prohibitions on the generation,  handling, storage,  transportation,  treatment
and  disposal  of  hazardous  substances  and waste from  spills,  releases  or
emissions  of  various  substances  produced  in  association  with oil and gas
operations. The legislation also requires that wells, facility sites, and other
properties  associated with the Company's  operations be operated,  maintained,
abandoned,   and  reclaimed  to  the  satisfaction  of  applicable   regulatory
authorities.  Under  environmental  legislation,  Compton  may  be  liable  for
personal injury, clean-up costs, remedial measures, and other environmental and
property damages, as well as administrative, civil, and criminal penalties.

Furthermore,  future changes in environmental  laws and regulations,  including
adoption of stricter standards or more stringent  enforcement,  could result in
curtailment  of  production  or  materially  increased  costs,  such as  fines,
incurred liability and increased capital  expenditures and operating costs, any
of which  could have a material  adverse  effect on  financial  condition.  For
example,  Canada is a signatory to the United Nations  Framework  Convention on
Climate  Change and has ratified the Kyoto Protocol  established  thereunder to
set legally binding targets to reduce  nationwide  emissions of carbon dioxide,
methane,  nitrous oxide,  and other  so-called  "greenhouse  gases."  Compton's
production facilities and other operations and activities emit greenhouse gases
that may subject the Company to legislation  regulating emissions of greenhouse
gases.  The  Government of Canada has proposed a Climate Change Plan for Canada
that suggests further  legislation will set greenhouse gases emission reduction
requirements  for  various  industrial   activities,   including  oil  and  gas
development  and  production.   Future  federal   legislation,   together  with
provincial emission reduction requirements, such as those proposed in Alberta's
Bill 32: Climate Change and Emissions Management,  may require the reduction of
emissions or emissions intensity of the Company's operations and facilities.

Compliance with such  legislation can require  significant  expenditures  and a
failure  to comply  may  result in the  issuance  of "clean  up"  orders or the
imposition  of fines  and  penalties,  some of  which  may be  material.  It is
possible  that the costs of complying  with  environmental  regulations  in the
future will have a material adverse effect on the Company's financial condition
or results of operations.  Compton may incur liabilities that could be material
or require the  Company to cease  production  on  properties  if  environmental
damage occurs.

Compton  has not  established  a separate  reclamation  fund for the purpose of
funding estimated future environmental and reclamation obligations. The Company
cannot  assure  that  it  will be able  to  satisfy  future  environmental  and
reclamation obligations.  Any site reclamation or abandonment costs incurred in
the ordinary  course in a specific  period will be funded out of cash flow from
operations.  Should  Compton be unable to fully fund the cost of  remedying  an
environmental  claim,  the Company  might be required to suspend  operations or
enter into  interim  compliance  measures  pending  completion  of the required
remedy.

The Company is not fully insured against certain  environmental  risks,  either
because such  insurance is not available or because of high premium  costs.  In
particular, insurance against risks from environmental pollution occurring over
time (as  opposed to sudden  and  catastrophic  damages)  is not  available  on
economically reasonable terms. Accordingly, Compton's properties may be subject
to  liability  due to hazards  that cannot be insured  against or that have not
been insured against due to prohibitive premium costs or for other reasons.

                                     -18-
<PAGE>

                           STATEMENT OF RESERVES DATA

Compton's  interests in its natural gas and crude oil properties as of December
31, 2005,  have been  evaluated  in a report (the  "REPORT") as of December 31,
2005,   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 net 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
does 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  and  these  variances  may be  material.  Compton  has no heavy oil
reserves and "crude oil" refers to light and medium crude oil only.

This statement is dated February 24, 2006.  The  information  being provided in
this  statement  has an effective  date of December 31, 2005 and a  preparation
date of February 24, 2006.

CONSTANT PRICES AND COSTS

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 the Alberta Royalty Tax Credit ("ARTC"), at the
end of the most recent fiscal year.

<TABLE>
<CAPTION>
SUMMARY OF OIL AND GAS RESERVES USING CONSTANT PRICING AS OF DECEMBER 31, 2005

-----------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1)              CRUDE OIL         NATURAL GAS (2)         NGLS              SULPHUR

                               GROSS      NET      GROSS        NET     GROSS      NET      GROSS      NET
                               (MBBL)   (MBBL)     (MMCF)     (MMCF)    (MBBL)   (MBBL)     (MLT)     (MLT)
-----------------------------------------------------------------------------------------------------------
<S>                           <C>      <C>       <C>        <C>        <C>       <C>       <C>       <C>
PROVED
Developed producing           14,222   13,206    430,136    349,723     7,937    5,635     1,605     1,428
Developed non-producing        3,195    2,951     44,496     35,519       830      566        52        41
Undeveloped                    5,029    4,313     84,539     70,260     1,731    1,278       118        98
-----------------------------------------------------------------------------------------------------------
TOTAL PROVED                  22,445   20,470    559,171    455,503    10,498    7,479     1,774     1,566
-----------------------------------------------------------------------------------------------------------
</TABLE>
(1)   Numbers may not add due to rounding.
(2)   The solution and associated  gas  represents 6% of the Company's  natural
      gas  reserves and is therefore  considered  immaterial  and is not broken
      out.

The  table set forth  below  summarizes  the net  present  value of future  net
revenue as of December 31, 2005 based on constant price and cost assumptions.

                                     -19-
<PAGE>

<TABLE>
<CAPTION>
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2005 (CONSTANT PRICES)

-----------------------------------------------------------------------------------------------
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                      $3,376,094     $1,609,730    $2,403,561    $1,183,126
Developed non-producing                     471,650        240,652       337,390       175,280
Undeveloped                                 795,420        301,318       557,529       213,100
-----------------------------------------------------------------------------------------------
TOTAL PROVED                             $4,643,164     $2,151,700    $3,298,480    $1,571,506
-----------------------------------------------------------------------------------------------
</TABLE>

(1)   A portion of the Company's  reserves  qualifies to receive 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.

<TABLE>
<CAPTION>
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2005 (CONSTANT PRICES)

-----------------------------------------------------------------------------------------------------------------------
  RESERVES   REVENUE      ROYALTIES   OPERATING  DEVELOPMENT       WELL         FUTURE NET   INCOME TAXES  FUTURE NET
  CATEGORY   ($000S)       ($000S)      COSTS       COSTS      ABANDONMENT    REVENUE BEFORE   ($000S)    REVENUE AFTER
                                       ($000S)     ($000S)    COSTS ($000S)    INCOME TAXES               INCOME TAXES
                                                                                 ($000S)                     ($000S)
-----------------------------------------------------------------------------------------------------------------------
<S>          <C>         <C>         <C>          <C>           <C>            <C>           <C>          <C>
Proved       $8,086,809  $1,514,951  $1,718,793   $187,687      $22,214        $4,643,164    $1,344,684   $3,298,480
-----------------------------------------------------------------------------------------------------------------------
</TABLE>

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

<TABLE>
<CAPTION>
TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2005 (CONSTANT PRICES)

----------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                 PRODUCTION TYPE                  FUTURE NET REVENUE BEFORE INCOME TAXES
                                                                        (DISCOUNTED AT 10%/YEAR) ($000S)
----------------------------------------------------------------------------------------------------------
<S>                       <C>                                                        <C>
Proved                    Crude Oil (1)                                              $  611,314
                          Natural Gas, ngls, and sulphur (2)                         $1,540,386
----------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Includes solution gas and related ngls.
(2)  Excludes solution gas and related ngls.

                                     -20-
<PAGE>

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.

<TABLE>
<CAPTION>
SUMMARY OF OIL AND GAS RESERVES USING FORECAST PRICING AS OF DECEMBER 31, 2005

---------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1)                 CRUDE OIL          NATURAL GAS            NGLS               SULPHUR

                                  GROSS      NET      GROSS       NET      GROSS      NET       GROSS      NET
                                  (MBBL)   (MBBL)     (MMCF)    (MMCF)     (MBBL)   (MBBL)      (MLT)     (MLT)
---------------------------------------------------------------------------------------------------------------
<S>                              <C>      <C>       <C>       <C>         <C>      <C>         <C>       <C>
PROVED
Developed producing              13,537   12,533    423,961   344,320      7,837    5,591      1,603     1,426
Developed non-producing           3,131    2,888     44,332    35,385        828      568         52        41
Undeveloped                       5,019    4,304     84,333    70,085      1,731    1,283        118        98
---------------------------------------------------------------------------------------------------------------
TOTAL PROVED                     21,688   19,725    552,626   449,790     10,396    7,441      1,773     1,565
PROBABLE                          6,805    5,762    401,415   337,719      6,232    4,629        772       656
---------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE       28,493   25,488    954,040   787,509     16,628   12,070      2,545     2,221
---------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Numbers may not add due to rounding.

The  tables  set forth  below  summarize  the net  present  value of future net
revenue as of December 31, 2005 based on forecast prices and cost assumptions.

<TABLE>
<CAPTION>
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2005 (FORECAST PRICES)

----------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1)                         NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)
                                                 BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR)
                                      0%            5%            8%           10%           15%           20%
----------------------------------------------------------------------------------------------------------------
<S>                              <C>           <C>           <C>          <C>           <C>           <C>
PROVED
Developed producing              $2,809,295    $1,790,246    $1,502,423   $1,367,244    $1,136,835      $989,296
Developed non-producing             407,231       275,162       231,040      209,205       170,528       145,066
Undeveloped                         673,954       369,776       278,044      234,937       162,989       119,410
----------------------------------------------------------------------------------------------------------------
TOTAL PROVED                      3,890,479     2,435,184     2,011,507    1,811,386     1,470,353     1,253,772
PROBABLE                          2,308,449     1,155,102       830,029      681,260       439,847       299,340
----------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE       $6,198,928    $3,590,286    $2,841,537   $2,492,645    $1,910,200    $1,553,112
----------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Numbers may not add due to rounding.

                                     -21-
<PAGE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1)                          NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)
                                                  AFTER INCOME TAXES DISCOUNTED AT (%/YEAR)
                                      0%            5%            8%           10%           15%           20%
-----------------------------------------------------------------------------------------------------------------
<S>                              <C>           <C>           <C>          <C>           <C>            <C>
PROVED
Developed producing              $2,023,759    $1,341,801    $1,126,747   $1,024,244    $  849,212     $  738,331
Developed non-producing             295,311       201,924       170,478      154,939       127,372        109,188
Undeveloped                         478,428       267,812       201,919      170,878       119,110         87,859
-----------------------------------------------------------------------------------------------------------------
TOTAL PROVED                      2,797,499     1,811,537     1,499,144    1,350,061     1,095,694        935,377
PROBABLE                          1,537,575       767,481       534,430      427,302       254,907        156,833
-----------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE       $4,335,073    $2,579,018    $2,033,574   $1,777,363    $1,350,601     $1,092,210
-----------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Numbers may not add due to rounding.

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

<TABLE>
<CAPTION>
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2005

--------------------------------------------------------------------------------------------------------------------
   RESERVES      REVENUE    ROYALTIES   OPERATING   DEVELOPMENT     WELL       FUTURE NET    INCOME     FUTURE NET
   CATEGORY      ($000S)     ($000S)      COSTS       COSTS     ABANDONMENT  REVENUE BEFORE  TAXES     REVENUE AFTER
                                         ($000S)     ($000S)      COSTS(1)    INCOME TAXES  ($000S)    INCOME TAXES
                                                                   ($000S)      ($000S)                   ($000S)
--------------------------------------------------------------------------------------------------------------------
<S>            <C>          <C>         <C>          <C>          <C>         <C>          <C>           <C>
Proved         $ 7,823,503  $1,436,847  $2,265,900   $192,916     $37,361     $3,890,479   $1,092,980    $2,797,499

Proved plus
probable       $12,577,769  $2,253,840  $3,251,277   $811,508     $62,216     $6,198,928   $1,863,855    $4,335,073
--------------------------------------------------------------------------------------------------------------------
</TABLE>

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

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

<TABLE>
<CAPTION>
         TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2005

--------------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY                    PRODUCTION TYPE            FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED
                                                                               AT 10%/YEAR) ($000S)
--------------------------------------------------------------------------------------------------------------------
<S>                         <C>                                                       <C>
Proved                      Crude Oil (1)                                             $  542,624
                            Natural Gas and ngls (2)                                  $1,268,762
Proved plus probable        Crude Oil (1)                                             $  645,369
                            Natural Gas and ngls (2)                                  $1,847,276
--------------------------------------------------------------------------------------------------------------------
</TABLE>
(1)   Includes solution gas and related ngls.
(2)   Excludes solution gas and related ngls.

                                     -22-
<PAGE>

                              PRICING ASSUMPTIONS

CONSTANT PRICES USED IN ESTIMATES

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
Netherland Sewell as of December 31, 2005.

<TABLE>
<CAPTION>
SUMMARY OF CONSTANT PRICING ASSUMPTIONS AS OF DECEMBER 31, 2005

---------------------------------------------------------------------------------------------------------------------
     YEAR                  CRUDE OIL               NATURAL GAS                NGLS                SULPHUR    EXCHANGE
                                                                                                              RATE
                   WTI CUSHING     EDMONTON PAR   AECO-C SPOT    PROPANE    BUTANE    PENTANES+  PLANT GATE $CDN/$US
                     OKLAHOMA     40 DEGREES API  ($CDN/MMBTU) ($CDN/BBL) ($CDN/BBL) ($CDN/BBL)  ($CDN/LT)
                     $ US/BBL       ($CDN/BBL)
---------------------------------------------------------------------------------------------------------------------
<S>                 <C>              <C>             <C>         <C>        <C>        <C>        <C>        <C>
Dec. 31, 2005       $61.04           $67.85          $9.99       $51.59     $63.52     $71.03     $13.17     0.858
---------------------------------------------------------------------------------------------------------------------
</TABLE>

FORECAST PRICES USED IN ESTIMATES

Future net revenue calculated using forecast prices and costs is based upon the
price assumptions set out below.  Netherland Sewell incorporated price forecast
which were the average of the December 31, 2005 pricing  forecasts  prepared by
four major  Canadian  consulting  firms in estimating  Compton's  reserves data
using forecast pricing and costs.

<TABLE>
<CAPTION>
SUMMARY OF FORECAST PRICING AND INFLATION RATE ASSUMPTIONS AS OF DECEMBER 31, 2005 (1)

-----------------------------------------------------------------------------------------------------------------------
   YEAR              CRUDE OIL           NATURAL GAS               NGLS                SULPHUR    INFLATION   EXCHANGE
                                                                                                      RATE (2)     RATE
             WTI CUSHING  EDMONTON PAR     AECO-C SPOT   PROPANE    BUTANE    PENTANES+  PLANT GATE   %/YEAR    $CDN/$US
              OKLAHOMA   40 DEGREES API   ($CDN/MMBTU)  ($CDN/BBL)($CDN/BBL) ($CDN/BBL)  ($CDN/LT)
               $US/BBL     ($CDN/BBL)
---------------------------------------------------------------------------------------------------------------------------
<S>           <C>           <C>              <C>         <C>         <C>        <C>        <C>         <C>         <C>
FORECAST
2006          $58.83        $68.13           $10.93      $43.28      $50.13     $69.99     $33.67      2.0%        0.85
2007          $58.30        $67.55           $ 9.91      $42.48      $49.67     $69.55     $23.77      2.0%        0.85
2008          $55.14        $63.80           $ 8.47      $39.95      $47.08     $65.80     $16.70      2.0%        0.85
2009          $52.32        $60.49           $ 7.72      $37.59      $44.74     $62.39     $15.14      2.0%        0.85
2010          $50.18        $57.96           $ 7.50      $35.93      $42.89     $59.83     $15.68      2.0%        0.85
2011          $49.18        $56.78           $ 7.56      $35.18      $41.94     $58.59     $16.38      2.0%        0.85
2012          $49.96        $57.66           $ 7.68      $35.75      $42.59     $59.49     $16.92      2.0%        0.85
2013          $50.97        $58.80           $ 7.84      $36.40      $43.44     $60.68     $17.47      2.0%        0.85
2014          $51.96        $59.98           $ 8.01      $37.15      $44.30     $61.88     $18.18      2.0%        0.85
2015          $53.01        $61.22           $ 8.21      $37.93      $45.19     $63.17     $18.91      2.0%        0.85
2016          $54.07        $62.42           $ 8.38      $38.70      $46.08     $64.46     $19.47      2.0%        0.85
Thereafter      2.0%          2.0%             2.0%        2.0%        2.0%       2.0%       2.0%      2.0%        0.85
---------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1)   Pricing  assumptions  are the average of four major  Canadian oil and gas
      evaluation firms.
(2)   Inflation rates for forecasting operating costs and capital investments.

The  weighted  average  realized  sales  price for  Compton  for the year ended
December  31, 2005 was  $8.42/MCF  for natural gas,  $62.02/BBL  for crude oil,
$47.34/BBL for ngls, and $12.63/LT for sulphur.

                                     -23-
<PAGE>

         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 forecast
price and cost assumptions, net of applicable royalties.

<TABLE>
<CAPTION>
RECONCILIATION  OF NET RESERVES BY RESERVE TYPE USING FORECAST PRICES AND COSTS (NET OF APPLICABLE ROYALTIES) (1)

-----------------------------------------------------------------------------------------------------------------
                                                    CRUDE OIL                                        NGLS

                                            NET         NET     NET PROVED        NET         NET     NET PROVED
                                         PROVED    PROBABLE  PLUS PROBABLE     PROVED    PROBABLE  PLUS PROBABLE
                                          (MBBL)      (MBBL)         (MBBL)     (MBBL)      (MBBL)         (MBBL)
-----------------------------------------------------------------------------------------------------------------
<S>                                      <C>       <C>       <C>               <C>       <C>       <C>
December 31, 2004                        11,018       6,669         17,687      6,256       3,520          9,776
Extensions                                1,532         359          1,891        431       1,921          2,352
Improved recovery                         3,626       1,671          5,297        190         379            569
Technical revisions                       4,057      (3,148)           909        614      (1,246)          (632)
Discoveries                                 409          42            451        260          45            305
Acquisitions                                514         169            683        208          10            218
Dispositions                                  -           -              -         (2)          -             (2)
Production                               (1,431)          -         (1,431)      (516)          -           (516)
-----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005                        19,725       5,762         25,488      7,441       4,629         12,070
-----------------------------------------------------------------------------------------------------------------


-----------------------------------------------------------------------------------------------------------------
                                                        NATURAL GAS                        SULPHUR

                                            NET         NET     NET PROVED        NET         NET     NET PROVED
                                         PROVED    PROBABLE  PLUS PROBABLE     PROVED    PROBABLE  PLUS PROBABLE
                                          (MBCF)      (MBCF)         (MBCF)      (MLT)       (MLT)          (MLT)
-----------------------------------------------------------------------------------------------------------------
December 31, 2004                       359,029     168,808        527,837      1,445         791          2,236
Extensions                               33,694     118,596        152,290          9         353            362
Improved recovery                        10,555      83,259         93,814          -           -              -
Technical revisions                      61,544     (45,976)        15,568        191        (488)          (297)
Discoveries                              16,310      12,362         28,672          -           -              -
Acquisitions                              5,564         670          6,234          -           -              -
Dispositions                                (56)          -            (56)         -           -              -
Production                              (36,850)          -        (36,850)       (80)          -            (80)
-----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005                       449,790     337,719        787,509      1,565         656          2,221
-----------------------------------------------------------------------------------------------------------------
</TABLE>
(1)  Prepared by Management. Numbers may not add due to rounding.

                                     -24-
<PAGE>

<TABLE>
<CAPTION>
RECONCILIATION OF NET RESERVES BY RESERVE TYPE USING FORECAST PRICES AND COSTS (1)

-----------------------------------------------------------------------------------------------------------------
                                                                                      TOTAL RESERVES

                                                                             NET             NET      NET PROVED
                                                                          PROVED        PROBABLE   PLUS PROBABLE
                                                                           (MBOE)          (MBOE)          (MBOE)
-----------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>           <C>         <C>
December 31, 2004                                                         78,557          39,115         117,672
Extensions                                                                 7,588          22,399          29,987
Improved recovery                                                          5,575          15,927          21,502
Technical revisions                                                       15,119         (12,545)          2,575
Discoveries                                                                3,387           2,147           5,535
Acquisitions                                                               1,649             291           1,940
Dispositions                                                                 (11)              -             (11)
Production                                                                (8,169)              -          (8,169)
-----------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2005                                                        103,696          67,334         171,031
-----------------------------------------------------------------------------------------------------------------
</TABLE>
(1)   Prepared by Management. Numbers may not add due to rounding.

FUTURE NET REVENUE RECONCILIATION

The following table reconciles changes between the future net revenue estimates
at December 31, 2005 and the  corresponding  estimates in the prior year, using
constant prices and costs, discounted at 10%.

<TABLE>
<CAPTION>
RECONCILIATION OF CHANGES IN NET PRESENT VALUE DISCOUNTED AT 10% OF FUTURE NET REVENUE OF PROVED RESERVES (1)

-----------------------------------------------------------------------------------------------------------------
                                                                                                       2005
                                                                                                      ($000S) (2)
-----------------------------------------------------------------------------------------------------------------
<S>                                                                                                   <C>
Estimated future net revenue at beginning of year                                                     $1,000,772
Sales and transfers of oil and gas produced, net of production costs and royalties                       336,711
Net change in sales, prices, production costs and royalties related to future production                 614,690
Changes in previously estimated development costs incurred during the period                            (306,199)
Changes in estimated future development costs                                                           (135,499)
Net change from extensions and improved recovery                                                         265,868
Net change from discoveries                                                                               88,318
Acquisitions of reserves                                                                                  (7,749)
Dispositions of reserves                                                                                      87
Net change resulting from revisions in quantity estimates                                                526,474
Accretion of discount                                                                                    100,077
Net change in income taxes(3)                                                                           (331,850)
-----------------------------------------------------------------------------------------------------------------
Estimated future net revenue at end of year                                                           $2,151,700
-----------------------------------------------------------------------------------------------------------------
</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.

                                     -25-
<PAGE>

                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. Although every reasonable effort
is made to ensure that reserve estimates are accurate, reserve estimation is an
inferential science. 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
conditions impacting oil and natural gas prices and costs change. Estimates are
reviewed  and  revised,  either  upward or  downward,  as  warranted by the new
information.

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


                                     -26-
<PAGE>

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:

<TABLE>
<CAPTION>
DEVELOPMENT COSTS DEDUCTED IN ESTIMATING FUTURE NET REVENUES (1)
----------------------------------------------------------------------------------------------------------
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
   2006                                      $106,989             $107,976                   $254,694
   2007                                        45,136               46,541                    222,114
   2008                                        24,156               25,511                    167,141
   2009                                         2,362                2,805                     70,830
   2010                                         4,659                5,229                     35,800
   Remaining                                   26,599               42,215                   123,2144
----------------------------------------------------------------------------------------------------------
Total undiscounted                           $209,901             $230,277                   $873,724

Total discounted at 10% per year             $171,801             $178,181                   $683,029
----------------------------------------------------------------------------------------------------------
</TABLE>
(1)   Includes abandonment costs. Numbers may not add due to rounding.

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.


                                     -27-
<PAGE>

                         OTHER OIL AND GAS INFORMATION

OIL AND GAS PROPERTIES AND WELLS

The following  table  summarizes the location of the Company's  interests as at
December  31, 2005,  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 WELLS
                            OIL WELLS         OIL WELLS       NATURAL GAS       GAS WELLS
                                                                 WELLS
                          GROSS     NET    GROSS      NET    GROSS     NET    GROSS     NET    GROSS      NET
-------------------------------------------------------------------------------------------------------------
<S>                       <C>       <C>    <C>        <C>    <C>       <C>    <C>       <C>    <C>      <C>
ALBERTA
    South                   108      48       32       12      820     525     216      176    1,176      761
    Central                 162      78       31        9      360     150     122       45      675      282
    Peace River Arch        334     207       26       11      122       -      24       14      506      233
BC                            6       -        2        -       42       2      12        1       62        3
-------------------------------------------------------------------------------------------------------------
TOTAL WELLS                 610     333       91       32    1,344     677     374      236    2,419    1,279
-------------------------------------------------------------------------------------------------------------
</TABLE>

The number of shut in oil and gas wells  capable of  production at December 31,
2005  increased  from 2004  because  well tie-ins were delayed as the result of
abnormally wet weather during the summer months of 2005.

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, 2005.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------
AREA                                                                           GROSS ACRES       NET ACRES
-------------------------------------------------------------------------------------------------------------
<S>                                                                                <C>               <C>
British Columbia                                                                   34,019            5,390
Alberta                                                                           907,482          704,148
Saskatchewan                                                                       23,157           23,157
Manitoba                                                                            6,659            6,259
-------------------------------------------------------------------------------------------------------------
TOTAL                                                                             971,317          738,954
-------------------------------------------------------------------------------------------------------------
</TABLE>

Approximately  211,270 net acres of  undeveloped  land could expire by December
31, 2006.  However,  the Company's 2006 exploration and development  activities
may defer the expiry of a portion of these  lands.  Compton  has $65 million of
work commitments associated with unproved properties.

FORWARD CONTRACTS

In 2005,  Compton's  realized average field price was $51.95/BOE,  comprised of
$8.42/MCF  for natural gas and  $56.04/BBL  for liquids.  In 2004,  the average
field  prices  of  natural  gas and  liquids  were  $6.46/MCF  and  $43.21/BBL,
respectively, for an average price of $39.82/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  10% of the Company's  natural gas production in 2005
was  committed  to  aggregators.  The average  aggregator  price  realized  was
$1.25/MCF less than the non-aggregator prices realized during the year.

                                     -28-
<PAGE>

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.

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  obligations ("ARO"). ARO cost
calculations were derived from a combination of actual third party cost quotes,
EUB cost models and typical industry  experience and practices.  The deemed ARO
liability for Compton's  1,449 net well sites 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 10.7% was used in the fair value calculation.

Total asset retirement  costs, net of estimated  salvage values, is $77 million
or $6 million when  discounted at 10%. The  undiscounted  ARO  associated  with
pipelines and facilities is $49 million and is not deducted in estimating total
future net revenue,  as calculated in the Company's reserve report. The Company
expects to pay $2 million dollars in ARO costs between 2006 and 2009.

TAX HORIZON

Based upon planned  capital  expenditure  programs and current  commodity price
assumptions,  it is  anticipated  the Company will not be cash taxable until at
least 2009.

CAPITAL EXPENDITURES

In 2005,  Compton incurred $72 million of exploration costs and $424 million of
development  costs.  Additionally,  $29  million  was spent on proved  property
acquisitions and $12 million was spent on unproved property acquisitions.


                                     -29-
<PAGE>

EXPLORATION AND DEVELOPMENT ACTIVITIES

The  following  table sets forth the number of crude oil and  natural gas 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,
2005 and 2004.  Four wells  drilled in 2005,  which are  standing  cased  wells
awaiting completion and testing, are not included in the following table.

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------------------
                                          YEAR ENDED DECEMBER 31, 2005              YEAR ENDED DECEMBER 31, 2004(1)
                                         DEVELOPMENT         EXPLORATORY           DEVELOPMENT        EXPLORATORY
                                        GROSS      NET     GROSS      NET        GROSS      NET     GROSS      NET
-------------------------------------------------------------------------------------------------------------------
<S>                                      <C>       <C>        <C>      <C>         <C>       <C>      <C>       <C>
Natural Gas                              197       156        60       56          108       89       31        26
Crude Oil                                104        96        10        9           29       17        -         -
Dry and Abandoned                          9         8         8        7            7        3       11        10
-------------------------------------------------------------------------------------------------------------------
TOTAL                                    310       260        78       72          144      110       42        36
SUCCESS RATIO                                          96%                                      90%
-------------------------------------------------------------------------------------------------------------------
(1)   2004 revised to include four wells previously classified as standing cased wells.
</TABLE>

In 2006,  the Company will continue to focus its resources in Alberta,  Canada.
Compton's  overall  objective  for  2006  is the  recognition  of its  unbooked
resource  potential.  The Company has  developed  an  aggressive  $575  million
capital expenditure plan for 2006, encompassing up to 480 gross wells.


                                     -30-
<PAGE>

PRODUCTION HISTORY

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

<TABLE>
<CAPTION>
GROSS NATURAL GAS AND LIQUIDS PRODUCTION

------------------------------------------------------------------------------------------------------------------
PRODUCT TYPE                                           FISCAL 2005 THREE MONTHS ENDED
                                                                                                      YEAR ENDED
                                           MARCH 31,    JUNE 30,  SEPTEMBER 30,      DECEMBER 31,   DECEMBER 31,
                                                2005        2005          2005               2005           2005
------------------------------------------------------------------------------------------------------------------
<S>                                        <C>          <C>       <C>                <C>            <C>
Natural gas (MMCF/D)                             130         130           130                133            131
Natural gas (MMCF)                            11,677      11,809        11,973             12,234         47,693

Liquids  (BOE/D)                               7,090       7,249         7,351              8,879          7,646
Liquids (MBBLS)                                  638         660           676                817          2,791
------------------------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------------------------
PRODUCT TYPE                                           FISCAL 2004 THREE MONTHS ENDED
                                                                                                      YEAR ENDED
                                          MARCH 31,    JUNE 30,   SEPTEMBER 30,       DECEMBER 31,   DECEMBER 31,
                                              2004        2004            2004               2004           2004
------------------------------------------------------------------------------------------------------------------
Natural gas (MMCF/D)                           120         122             123                127            123
Natural gas (MMCF)                          10,954      11,094          11,347             11,725         45,120

Liquids (BOE/D)                              5,655       5,977           6,712              6,963          6,330
Liquids (MBBLS)                                515         544             618                640          2,317
------------------------------------------------------------------------------------------------------------------
</TABLE>

2006 PRODUCTION ESTIMATES

Production  volumes  in  2006  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 case.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------
RESERVES CATEGORY (1)                   CRUDE OIL     NATURAL GAS       NGLS        SULPHUR           TOTAL
                                         (BBL/D)       (MMCF/D)       (BBL/D)         (LT/D)         (BOE/D)
------------------------------------------------------------------------------------------------------------
<S>                                        <C>              <C>          <C>            <C>          <C>
PROVED
Developed producing                        4,944             99          1,726          178          23,267
Developed non-producing                    1,394             14            230            3           3,934
Undeveloped                                  994              7            184            -           2,406
------------------------------------------------------------------------------------------------------------
TOTAL PROVED                               7,332            120          2,140          181          29,606
PROBABLE                                     384             23            302           13           4,614
------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                 7,716            143          2,442          194          34,221
------------------------------------------------------------------------------------------------------------
(1)   Numbers may not add due to rounding. Based on estimates only. Variances may occur due to circumstances
      beyond Compton's control.
</TABLE>

                                     -31-
<PAGE>

The  Company's  field  netbacks  for  natural  gas and  liquids for each of the
periods indicated is set forth below.

<TABLE>
<CAPTION>
NATURAL GAS AND LIQUIDS FIELD NETBACKS

-------------------------------------------------------------------------------------------------------------------
                                                      FISCAL 2005 THREE MONTHS ENDED
                                                                                                        YEAR ENDED
                                          MARCH 31,      JUNE 30,   SEPTEMBER 30,     DECEMBER 31,     DECEMBER 31,
                                              2005          2005            2005             2005             2005
-------------------------------------------------------------------------------------------------------------------
<S>                                        <C>          <C>         <C>              <C>              <C>
NATURAL GAS ($/MCF)
Revenue price                                $6.60         $7.28           $8.46           $11.20            $8.42
Royalties, net                               (1.66)        (1.76)          (2.23)           (2.54)           (2.06)
Operating costs                              (1.03)        (1.01)          (1.00)           (1.10)           (1.04)
Transportation costs                         (0.13)        (0.17)          (0.19)           (0.18)           (1.07)
-------------------------------------------------------------------------------------------------------------------
Field netback                                $3.78         $4.34           $5.05           $ 7.38            $5.15

LIQUIDS ($/BBL)
Revenue price                               $46.23        $54.20          $64.75           $57.99           $56.04
Royalties, net                               (9.99)       (10.53)         (13.37)          (15.24)          (12.36)
Operating costs                              (6.15)        (6.09)          (5.98)           (6.63)           (6.22)
Transportation costs                         (0.80)        (1.01)          (1.13)           (1.09)           (1.01)
-------------------------------------------------------------------------------------------------------------------
Field netback                               $29.29        $36.56          $44.28           $35.03           $36.45
-------------------------------------------------------------------------------------------------------------------

-------------------------------------------------------------------------------------------------------------------
                                                      FISCAL 2004 THREE MONTHS ENDED
                                                                                                        YEAR ENDED
                                          MARCH 31,      JUNE 30,   SEPTEMBER 30,     DECEMBER 31,     DECEMBER 31,
                                              2004          2004            2004             2004             2004
-------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/MCF)
Revenue price                                $6.25         $6.84           $6.48            $6.29            $6.46
Royalties, net                               (1.48)        (1.57)          (1.64)           (1.64)           (1.58)
Operating costs                              (0.91)        (0.92)          (0.93)           (1.01)           (0.94)
Transportation costs                         (0.14)        (0.14)          (0.13)           (0.16)           (0.15)
-------------------------------------------------------------------------------------------------------------------
Field netback                                $3.72         $4.21           $3.78            $3.48            $3.79

LIQUIDS ($/BBL)
Revenue price                               $40.03        $42.75          $46.60           $42.88           $43.21
Royalties, net                               (8.88)        (9.40)          (9.82)           (9.82)           (9.50)
Operating costs                              (5.46)        (5.51)          (5.59)           (6.05)           (5.66)
Transportation costs                         (0.84)        (0.86)          (0.81)           (0.98)           (0.87)
-------------------------------------------------------------------------------------------------------------------
Field netback                               $24.85        $26.98          $30.38           $26.03           $27.18
-------------------------------------------------------------------------------------------------------------------
</TABLE>

                                     -32-
<PAGE>

                                   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  127,294,201  common shares are
issued and outstanding as fully paid and  non-assessable  share as at March 23,
2006. No preferred  shares are issued and outstanding as at March 23, 2006. 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.

SHAREHOLDER RIGHTS PLAN

Compton has a shareholder  rights plan (the "RIGHTS PLAN") under the terms of a
shareholder  rights  plan  agreement  dated as of April 22,  2003  between  the
Company and Computershare  Trust Company of Canada, as rights agent. The Rights
Plan is designed to encourage the fair treatment of  shareholders in connection
with a take-over  bid for Compton.  Rights  issued under the Rights Plan become
exercisable when a person,  and any related parties,  acquires or announces its
intention  to acquire  20% or more of the  outstanding  Common  Shares  without
complying  with  certain  provisions  set out in the  Rights  Plan  or  without
approval of the Board of Directors of Compton.  Should such an  acquisition  or
announcement  occur,  each rights holder,  other than the acquiring  person and
related  parties,  will  have the  right to  purchase  Common  Shares  at a 50%
discount to the market price at that time.


                                     -33-
<PAGE>

                             MARKET FOR SECURITIES

The  outstanding  common  shares of the Company are listed on the Toronto Stock
Exchange  ("TSX") under the symbol CMT and on the New York Stock Exchange until
the symbol CMZ. The  following  table sets out the high and low closing  prices
and average  trading  volume of common  shares as reported by the TSX,  for the
periods indicated.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------
  PERIOD                TSX HIGH CLOSE   TSX LOW CLOSE    TSX AVERAGE DAILY TRADING VOLUME
------------------------------------------------------------------------------------------
<S>                         <C>             <C>                      <C>
2005
  January                   $11.65          $10.51                   516,574
  February                  $12.65          $11.46                   667,961
  March                     $13.74          $11.30                   634,532
  April                     $12.45          $10.26                   549,281
  May                       $10.82          $ 9.95                 1,065,189
  June                      $11.65          $10.70                   842,449
  July                      $13.70          $11.32                   809,324
  August                    $14.21          $13.10                   835,428
  September                 $15.90          $13.90                   700,544
  October                   $16.00          $12.90                   562,113
  November                  $15.40          $12.65                   691,408
  December                  $18.40          $16.69                   951,082

2006
  January                   $18.84          $17.01                   743,850
  February                  $18.92          $14.39                   773,430
  March 1-23                $15.87          $13.95                   668,241
------------------------------------------------------------------------------------------
</TABLE>


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

                                      -34-
<PAGE>

                               MATERIAL CONTRACTS

Indenture  dated as of  November  22,  2005,  among  Compton  Petroleum  Finance
Corporation, Compton, as parent guarantor, Hornet Energy Ltd., Compton Petroleum
(partnership)  and  Compton  Petroleum  Holdings  Corporation,  as  the  initial
subsidiary guarantors, and The Bank of Nova Scotia Trust Company of New York, as
trustee,  whereby,  on November 22, 2005, Compton Petroleum Finance  Corporation
issued and sold  U.S.$300  million  aggregate  principal  amount of senior  term
notes,  which are  unsecured  and bear  interest  semi-annually,  in  arrears on
December 1, and June 1 of each year, at a rate of 7 5/8% per year with principal
repayable on December 1, 2013.  The senior notes are  guaranteed  by Compton and
the initial subsidiary guarantors.


                              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  ("S&P") and Moody's  Corporation  ("MOODY'S")
have rated  Compton's  U.S.  300 million 7 5/8% Senior  Notes as B stable and B2
stable  respectively,  as at  December  31,  2005.  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.

An S&P credit rating considers likelihood of payment,  nature of and provisions
of the  obligation,  protection  afforded  by, and  relative  position  of, the
obligation in the event of  bankruptcy,  reorganization,  or other  arrangement
under the laws of bankruptcy and other laws affecting  creditors' rights. S&P's
credit  ratings are on a long-term debt rating scale that ranges from AAA to D,
representing the range from highest to lowest quality of such securities rated.
The ratings  from AA to CCC may be  modified  by the  addition of a plus (+) or
minus (-) sign to show relative  standing  within the major rating  categories.
According to the S&P rating system,  debt securities  rated B are vulnerable to
nonpayment,  but the obligor  currently  has the capacity to meet its financial
commitment  on  the  obligation.   Adverse  business,  financial,  or  economic
conditions will likely impair the obligor's capacity or willingness to meet its
financial commitment on the obligation.

Moody's credit ratings on long-term  structured finance  obligations  primarily
address the expected credit loss an investor might incur on or before the legal
final maturity of such  obligations,  incorporating  the probability of default
and the severity of the loss.  Moody's  credit  ratings are on a long-term debt
rating  scale  that  ranges  from Aaa to C,  representing  the range from least
credit risk to greatest credit risk of such securities  rated.  Moody's applies
numerical  modifiers 1, 2 and 3 in each generic rating  classification  from Aa
through Caa in its long term debt rating system.  The modifier 1 indicates that
the issue ranks in the higher end of its generic rating category,  the modifier
2 indicates a mid-range  ranking,  and the modifier 3 indicates  that the issue
ranks in the  lower  end of that  generic  rating  category.  According  to the
Moody's rating system, debt securities rated B2 are considered  speculative and
are subject to high credit risk.

                                     -35-
<PAGE>

                             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 Meeting of  Shareholders is scheduled for May 10,
2006 at 3:30 pm. (Calgary time) in the Historical  Ballroom on the 4th Floor of
the Calgary Chamber of Commerce,  517 - Centre Street South, Calgary,  Alberta,
Canada.

The Board of Directors has established an Audit, Finance and Risk Committee; an
Engineering,   Operations   and   Reserves   Committee;   a  Human   Resources,
Compensation,  Environmental,  Health and  Safety  Committee;  and a  Corporate
Governance  Committee.  All  independent  Directors  sit on each  of the  Board
Committees.  Mr.  Sapieha  does not sit on the Board  Committees  since he is a
non-independent  Director  due to his  position  as  President  & CEO  with the
Company.

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.           Group Vice  President,  Corporate  Law,  of Enbridge  Inc.,  an energy       1993
Calgary, AB, Canada           transportation  and  distribution  company.  Mr.  Belich has also been
                              Chairman  and  President  of  each  of  Enbridge  International  Inc.,
                              Enbridge   Technology  Inc.,  and  a  director  of  numerous  Enbridge
                              affiliates, including those in Europe and Latin America.

                              Mr. Belich is the Chairman of the Board of
                              Directors of Compton and the Chairman of the
                              Corporate Governance Committee.
---------------------------------------------------------------------------------------------------------------------

Irvine J. Koop, P. Eng.       Chairman and Chief Executive Officer,  IKO Resources Inc., a petroleum       1996
Calgary, AB, Canada           consulting  firm and prior thereto,  President and CEO,  Pipelines and
                              Midstream of Westcoast Energy Inc.

                              Mr. Koop is the Chairman of the Human Resources,
                              Compensation, Environmental, Health and Safety
                              Committee.
---------------------------------------------------------------------------------------------------------------------

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

Ernie G. Sapieha, C.A.        President & Chief Executive Officer of the Company.                          1993
Calgary, AB, Canada
---------------------------------------------------------------------------------------------------------------------

Jeffrey T. Smith, P. Geol.    Independent  Businessman and prior thereto, Chief Operating Officer of       1999
Calgary, AB, Canada           Northstar Energy Corporation.

                              Mr. Smith is Chairman of the Engineering,
                              Reserves and Operations Committee.
---------------------------------------------------------------------------------------------------------------------
</TABLE>

                                     -36-
<PAGE>

<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
NAME AND MUNICIPALITY OF                               PRINCIPAL OCCUPATION                           DIRECTOR SINCE
RESIDENCE
---------------------------------------------------------------------------------------------------------------------
<S>                           <C>                                                                          <C>
John A. Thomson, C.A.         Independent   Businessman.   Mr.  Thomson  served  as  Vice  President       2003
Calgary, AB, Canada           Corporate  Development  from 2000 and as a director from 1999 to 2001,
                              of Avid Oil & Gas Ltd., an oil and gas company and prior  thereto,  he
                              was Senior Vice President and Chief  Financial  Officer of Renaissance
                              Energy Ltd., an oil and gas Company.

                              Mr. Thomson is the Chairman of the Audit,
                              Finance and Risk Committee.
---------------------------------------------------------------------------------------------------------------------
</TABLE>

Further  information  about the  Directors  and the  committees of the Board of
Directors  is set forth  under  the  heading  "Election  of  Directors"  in the
Company's Management Proxy Circular dated March 15, 2006 relating to the Annual
Meeting  of  Shareholders  to be held  on May  10,  2006,  which  sections  are
incorporated by reference into this Annual Information Form.

OFFICERS

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

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------

NAME AND MUNICIPALITY OF RESIDENCE                               PRINCIPAL OCCUPATION
----------------------------------------------------------------------------------------------------------------
<S>                                  <C>
Ernie 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; prior
Calgary, Alberta                     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

Marc R. Junghans, P. Geol.           Vice President Exploration; prior to 2002, Manager of Exploration of the
Calgary, Alberta                     Company.
----------------------------------------------------------------------------------------------------------------
</TABLE>

As at March  23,  2006,  the  Directors  and  officers  of  Compton  as a group
beneficially  owned or controlled,  directly or indirectly,  12,920,564  common
shares  of  Compton,   representing  approximately  10.2%  of  the  issued  and
outstanding  common  shares of the Company.  None of the  Directors or Officers
held a sufficient  number of common shares to materially  affect the control of
Compton.


                                     -37-
<PAGE>

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

Based upon  applicable  Canadian and United States  securities laws and the New
York Stock Exchange corporate  governance rules, Compton has adopted "Standards
of  Independence,"  which may be viewed in full on the Company's  website.  The
Board  affirmatively  determines  on an annual  basis the  independence  of its
members. Messrs. Belich, Koop, Preston, Smith, and Thomson have been determined
to be independent Directors. Mr. Sapieha is not an independent Director because
of his position as President & CEO of the Company.

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, due to their
experience in various management positions.

EXTERNAL AUDITOR FEES

The  aggregate  amounts  paid or accrued by the  Company  with  respect to fees
payable to Grant Thornton LLP 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,
2005 and 2004 were as follows:

--------------------------------------------------------------------------------
TYPE OF SERVICE                                FISCAL 2005      FISCAL 2004 (1)
--------------------------------------------------------------------------------
Audit                                             $481,230         $350,455
Audit related                                      221,997          131,315
Tax                                                 10,000            9,000
Other non-audit                                     41,930           49,598
--------------------------------------------------------------------------------
Total                                             $755,157         $540,368
--------------------------------------------------------------------------------

(1)   2004 amounts have been updated to account for differences between accrued
      costs and actual billings.

The audit related fees incurred in fiscal 2005 related to the Company's  equity
offering in February 2005 and the issuance of the Company's U.S.  dollar Senior
Notes in November  2005. Tax fees incurred in fiscal 2005 related to the review
of tax forms  and the fees for other  non-audit  services  in fiscal  2005 were
incurred to translate the Company's quarterly and annual reports into French.

The audit related fees incurred in fiscal 2004 related to discussions regarding
the  accounting  treatment  for the Mazeppa  Processing  Partnership.  Tax fees
incurred  in fiscal  2004  related  to the review of tax forms and the fees for
other  non-audit  services  in  fiscal  2004 were  incurred  to  translate  the
Company's  quarterly and annual reports into French and  discussions  regarding
requirements of the Sarbanes Oxley Act of 2002.

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  LLP 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 LLP 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.


                                     -38-
<PAGE>

                          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.

                             ADDITIONAL INFORMATION

Additional   information  including  Directors'  and  Officers'   remuneration,
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 March 15,
2006,  relating to the Annual and Special Meeting of Shareholders to be held on
May  10,  2006.  Additional  financial  information  is  also  provided  in the
consolidated  financial  statements  and MD&A of the Company for the year ended
December 31, 2005 included in the Company's 2005 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.

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

            Compton Petroleum Corporation
            Suite 3300, 425 - 1st Street S.W.
            Fifth Avenue Place, East Tower
            Calgary, Alberta, Canada
            T2P 3L8

            Attention:   Mr. T.G. Millar
                         Vice President, General Counsel & Corporate Secretary
            Telephone:   (403) 237-9400
            Fax:         (403) 237-9410



                                     -39-
<PAGE>


                                   SCHEDULE A

                     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 December 31, 2005. The
     reserves data consist of the following:

     (a)   (i)      proved and proved plus probable oil and gas
                    reserves estimated as at December 31, 2005 using
                    forecast prices and costs; and

           (ii)     the related estimated future net revenue; and

     (b)   (i)      proved and proved plus probable oil and gas
                    reserves estimated as at December 31, 2005 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, 2005 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   Canadian federal income taxes, 10% discount rate)(C$)
      Reserves Evaluator or     of Evaluated     of         -----------------------------------------------------
             Auditor               Report        Reserves   Audited     Evaluated     Reviewed        Total
     ------------------------------------------------------------------------------------------------------------
     <S>                       <C>                            <C>      <C>               <C>       <C>
     Netherland, Sewell &      February 24, 2006  Canada      nil      2,492,645.40      nil       2,492,645.40
     Associates, Inc.
</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.


                                     -40-
<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
                                      March 14, 2006

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






Please be advised  that the  digital  document  you are  viewing is provided by
Netherland,  Sewell & Associates,  Inc. (NSAI) as a convenience to our clients.
The digital document is intended to be  substantively  the same as the original
signed  document  maintained  by NSAI.  The digital  document is subject to the
parameters, limitations, and conditions stated in the original document. In the
event  of any  differences  between  the  digital  document  and  the  original
document,  the  original  document  shall  control  and  supersede  the digital
document.

                                     -41-
<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, 2005 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,
                       2005 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, Reserves and Operations 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,  Reserves and Operations  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, Reserves and Operations 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.


                                     -42-
<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 & Engineering

(signed) "Jeffrey Smith"                (signed) "Mel Belich"
Jeffrey Smith                           Mel Belich
Chairman of the Engineering, Reserves   Chairman of the Board
and Operations Committee

March 23, 2006



                                     -43-
<PAGE>

                                   SCHEDULE C

                CHARTER OF THE AUDIT, FINANCE AND RISK COMMITTEE


MANDATE OF THE COMMITTEE

The  Audit,  Finance  and Risk  Committee  (the  "COMMITTEE")  of the  Board of
Directors (the "BOARD") of Compton Petroleum Corporation (the "COMPANY") shall,
as permitted by the Business  Corporations  Act (Alberta)  (the "ABCA") and the
Articles and By-Laws of the Company,  have the  responsibility  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.

The Committee has the authority to obtain  independent  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 has the  responsibility  to, without
limitation:

(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;

                                     -44-
<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  Human   Resources,   Compensation,
     Environmental,  Health and Safety  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 management 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, and
     in addition:

                                     -45-
<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 and as required by the
     Corporate Governance Committee, the Company's Code of Business Conduct and
     Ethics;

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

     (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.   at least annually,  obtain and review a report by the independent  auditor
     describing the firm's internal  quality control  procedures;  any material
     issues raised by the most recent internal  quality-control review, or peer
     review, of the firm, or by any inquiry or investigation by governmental or
     professional authorities,  within the preceding five years, respecting one
     or more independent audits carried out by the firm, and any steps taken to
     deal with any such issues; and (to assess the auditor's  independence) all
     relationships between the independent auditor and the listed company;

4.   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;

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

6.   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;

7.   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;

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

                                     -46-
<PAGE>

9.   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
     the planned steps for an orderly transition period;

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

11.  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;

12.  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;

13.  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;

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

15.  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;

                                     -47-
<PAGE>

(D)  ADDITIONAL DUTIES AND RESPONSIBILITIES

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

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

The Committee also has the responsibility to:

1.   with the approval of the Board or the  Corporate  Governance  Committee of
     the Board retain and  compensate  independent  advisors  (including  legal
     counsel), as deemed necessary by the Committee;

2.   meet separately with senior management,  employees or independent advisors
     in respect of audit,  finance and risk matters, as deemed necessary by the
     Committee;

3.   review and assess  annually the adequacy of this Charter and recommend any
     approved changes to the Corporate Governance Committee and the Board;

4.   annually evaluate the performance of the Committee and Committee Chair;

5.   prepare the  Committee's  report or reports for  publication in applicable
     disclosure documents, including the Audit Committee Report for publication
     in the annual Management Information Circular;

6.   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;

7.   fulfill its responsibilities and duties by:

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

     (b)      meeting  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;

8.   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;

9.   consider and make recommendations to the Board with respect to any matters
     properly referred to the Committee by the Board;

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

                                     -48-
<PAGE>

COMPOSITION OF THE COMMITTEE

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

2.   Each  member of the  Committee  shall be  "independent"  as  affirmatively
     determined  by the Board,  and as defined in the  Company's  Standards  of
     Independence attached hereto.

3.   At least half of the members of the Committee must be resident  Canadians,
     as that term is defined in the ABCA.

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; and

     (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  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.

                                     -49-
<PAGE>

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.


                                     -50-
<PAGE>

                         COMPTON PETROLEUM CORPORATION
                           STANDARDS OF INDEPENDENCE

Compton  Petroleum  Corporation  ("Compton"  or "the  Company") has adopted the
following  standards for determining  whether a director is independent  within
the meaning of applicable  Canadian and United States  securities  laws and the
New York Stock Exchange corporate governance rules.

These Standards will be periodically  reviewed and may be modified by Compton's
Board of Directors  ("the  Board").  Except where required by applicable law or
the  rules of the New York  Stock  Exchange,  the  criteria  set forth in these
standards  are not intended to  constitute  rigid rules that govern the Board's
determination  of  whether a director  is  independent  from the  Company or an
interpretation of any applicable law, rule or regulation.

To be considered  independent for purposes of these  standards,  the Board must
affirmatively determine on an annual basis that the director being reviewed has
no direct or  indirect  material  relationship  with the  Company.  A "material
relationship"  is a  relationship  which  could,  in the view of the  Company's
Board,  be  reasonably  expected to  interfere  with the exercise of a member's
independent judgment. In each case, the Board shall consider all relevant facts
and circumstances.

Additionally, a director will not be deemed to be independent if:

(a)  the director  is, or has been within the last three years,  an employee or
     executive officer of the Company,  or an immediate family member(1) of the
     director is, or has been within the last three years, an executive officer
     of the Company;

(b)  the  director  is a  current  partner  or  employee  of a firm that is the
     Company's  internal  or  external  auditor,  or was  within the last three
     years, a partner(2) or employee of that firm and personally  worked on the
     Company's audit within that time;

(c)  an immediate  family member of the director is a current partner of a firm
     that is the  Company's  internal  or  external  auditor,  or is a  current
     employee  of that firm and  participates  in its audit,  assurance  or tax
     compliance (but not tax planning) practice,  or was, within the last three
     years a partner  or  employee  of that firm and  personally  worked on the
     Company's audit within that time;

(d)  the director,  or an immediate  family  member of the director,  is or has
     been within the last three  years,  an  executive  officer of an entity on
     which any of the Company's current executive  officers serves or served at
     that same time on the entity's compensation committee;

(e)  the director or an immediate family member of the director who is employed
     as an  executive  officer of the Company has  received,  during any twelve
     month  period  within the last three  years,  more than  $75,000 in direct
     compensation from the Company,  other than 1) director and committee fees,
     2) pension  or other  forms of  deferred  compensation  for prior  service
     provided that such  compensation is not contingent in any way on continued
     service and 3)  compensation  for  previously  acting as an interim  chief
     executive officer of the Company or previously acting as a chairman of the
     board on a part-time basis;

(f)  the director is a current  employee,  or an immediate  family  member is a
     current  executive  officer,  of a company  that has made  payments to, or
     received  payments from, the Company for property or services in an amount
     which,  in any of the last three fiscal  years,  exceeds the greater of $1
     million, or 2% of such other company's consolidated gross revenues;

(g)  the director accepts, directly or indirectly, any consulting,  advisory or
     other  compensatory  fee from the Company or any subsidiary  entity of the
     Company,  other than as remuneration for acting in the director's capacity
     as a member of the board or any board  committee,  or as a part-time chair
     or  vice-chair  of the board or any board  committee;  or is an affiliated
     entity of the Company or any of its subsidiary entities.

     Other  compensatory  fees  includes  acceptance  of a fee by an  immediate
     family member or an entity in which the director is a partner,  member, an
     officer such as a managing  director  occupying a  comparable  position or
     executive  officer,   or  occupies  a  similar  position  (except  limited
     partners,  non-managing members and those

                                     -51-
<PAGE>

     occupying  similar  positions  who,  in each case,  have no active role in
     providing   services  to  the  entity)  and  which  provides   accounting,
     consulting,  legal,  investment  banking or financial advisory services to
     the Company or any subsidiary entity of the Company.  Compensatory fees do
     not  include  the  receipt  of  fixed  amounts  of  compensation  under  a
     retirement plan (including  deferred  compensation) for prior service with
     the Company if the  compensation is not contingent in any way on continued
     service.


(h)  the director is an affiliated(3) person of the Company.
















(1)  An immediate  family  member is defined as a director's  spouse,  parents,
     children, siblings, mothers and fathers-in-law, sons and daughters-in-law,
     brothers and  sisters-in-law,  and anyone (other than domestic  employees)
     who shares the director's home.

(2)  A partner does not include a fixed income  partner  whose  interest in the
     firm that is the internal or external auditor is limited to the receipt of
     fixed amounts of compensation  (including deferred compensation) for prior
     service with that firm if the compensation is not contingent in any way on
     continued service.

(3)  Affiliated person of another person means:

     (a)  any person  directly or indirectly  owning,  controlling,  or holding
          with power to vote, 5% or more of the outstanding  voting  securities
          of such other person;

     (b)  any  person 5% or more of whose  outstanding  voting  securities  are
          directly or indirectly owned, controlled, or held with power to vote,
          by such other person;

     (c)  any person  directly or  indirectly  controlling,  controlled  by, or
          under common control with, such other person;

     (d)  any officer, director,  partner, copartner, or employee of such other
          person;

     (e)  if such other person is an investment company, any investment adviser
          thereof or any member of an advisory board thereof; and

     (f)  if such other  person is an  unincorporated  investment  company  not
          having a board of directors, the depositor thereof.