EXHIBIT 20.1
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                               [GRAPHIC OMITTED]



                           C   O   M   P   T   O   N
                           -------------------------
                             PETROLEUM CORPORATION



                            ANNUAL INFORMATION FORM
                      FOR THE YEAR ENDED DECEMBER 31, 2007



















                                 March 25, 2008



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<PAGE>

                               TABLE OF CONTENTS

                                                                           PAGE

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

DEFINITIONS...................................................................3

ADVISORIES....................................................................8

CORPORATE STRUCTURE...........................................................9

GENERAL DEVELOPMENT OF THE BUSINESS..........................................10

DESCRIPTION OF THE BUSINESS..................................................11

RISK FACTORS.................................................................17

STATEMENT OF RESERVES DATA...................................................21

DIVIDENDS....................................................................34

CAPITAL STRUCTURE............................................................34

MARKET FOR SECURITIES........................................................35

CONFLICTS OF INTEREST........................................................36

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS..................36

CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS.....................36

MATERIAL CONTRACTS...........................................................37

LEGAL PROCEEDINGS AND REGULATORY ACTIONS.....................................37

INTERESTS OF EXPERTS.........................................................37

RATINGS......................................................................38

DIRECTORS AND OFFICERS.......................................................38

AUDIT, FINANCE AND RISK COMMITTEE INFORMATION................................40

TRANSFER AGENT AND REGISTRAR.................................................41

ADDITIONAL INFORMATION.......................................................42

SCHEDULE A...................................................................43

SCHEDULE B...................................................................45

SCHEDULE C...................................................................47



                                      -1-

<PAGE>

                      ABBREVIATIONS AND CONVERSION FACTORS


ABBREVIATIONS

The following are abbreviations of technical terms used throughout this Annual
Information Form:

"BBL" means barrel;

"BBL/D" means barrels per day;

"BBLS" means barrels;

"BOE" means barrels of crude oil equivalent;

"BOEPD" or "BOE/D" means barrels of crude oil equivalent per day;

"KM(2)" means square kilometres;

"LT" means long ton;

"MBBLS" means thousand barrels;

"MBOE" means thousand barrels of crude oil equivalent;

"MCF" means thousand cubic feet;

"MCFE" means thousand cubic feet equivalent;

"MI" means miles;

"MI(2)" means square miles;

"MLT" means thousands of long tons;

"MMBBLS" means million barrels;

"MMBOE" means million barrels of crude oil equivalent;

"MMBTU" means million British thermal units;

"MMCF" means million cubic feet;

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

"MMCFE" means million cubic feet equivalent; 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
-------------------------------------------------------------------------------
boe                              Mcfe                              6.000
cubic feet                       cubic metres of gas               0.028
cubic metres of gas              cubic feet                       35.490
bbls of oil                      cubic metres                      0.159
cubic metres                     bbls of oil                       6.289
feet                             metres                            0.305
metres                           feet                              3.281
miles                            kilometres                        1.609
kilometres                       miles                             0.621
acres                            hectares                          0.400
hectares                         acres                             2.500
-------------------------------------------------------------------------------


                                  DEFINITIONS

The  following  terms,  when used in this  Annual  Information  Form,  have the
following  meanings  and,  where  applicable,  are as  set  forth  in  National
Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities," issued
by the Canadian Securities Administrators ("CSA").

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

"COMPANY" or  "COMPTON" or "WE" means  Compton  Petroleum  Corporation  and its
partnership and subsidiaries where the context so requires.

"CRUDE  OIL" or "OIL" means a mixture  that  consists  mainly of  pentanes  and
heavier  hydrocarbons,  which may  contain  small  amounts of 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  defence,  and the  maintenance  of land and
            lease records;

     (c)    dry hole contributions and bottom hole contributions;

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

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

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


                                      -4-
<PAGE>

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

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

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

"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 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 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.


                                      -5-
<PAGE>

"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;

     (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  and  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 the
            Company  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.


                                      -6-
<PAGE>

"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.

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

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

"RESERVOIR"  means a  porous  and  permeable  subsurface  rock  formation  that
contains a separate  accumulation  of petroleum that is confined by impermeable
rock or water barriers and is characterized by a single pressure system.

"SECTION" means one square mile or 640 acres.

"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 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.


                                      -7-
<PAGE>

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


                                   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 and does not represent a value equivalency at the
wellhead.  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  information and statements under the meaning of applicable  securities
laws, including Canadian Securities  Administrators' National Instrument 51-102
Continuous  Disclosure  Obligations  and the United States  Private  Securities
Litigation Reform Act of 1995. Forward looking statements include  assumptions,
estimates, plans, expectations,  opinions, forecasts, projections, guidance, or
other  statements  that  are  not  statements  of  fact,  including  statements
regarding (i) cash flow, 2008 production estimates,  reserve estimates, capital
expenditures,  operating  expenditures,  2008 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 and assumptions  reflected in
such forward looking  statements are reasonable,  it can give no assurance that
such  assumptions and expectations  will prove to have been correct.  There are
many factors that could cause  forward  looking  statements  not to be correct,
including risks and  uncertainties  inherent in the Company's  business.  These
risks  include,  but are not  limited  to:  crude  oil and  natural  gas  price
volatility, exchange rate fluctuations,  availability of services and supplies,
operating hazards, access difficulties and mechanical failures, weather related
issues,  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.
Statements   relating  to   "reserves"   or   "resources"   are  deemed  to  be
forward-looking  statements,  as they involve the implied assessment,  based on
estimates and assumptions,  that the reserves and resources  described exist in
the quantities  predicted or estimated,  and can be profitably  produced in the
future.  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,  but Compton does not  undertake to update this
information  at any particular  time,  except as required by law. The Company's
forward  looking  statements are expressly  qualified in their entirety by this
cautionary  statement.   Compton  cautions  readers  that  the  forward-looking
statements  may not be  appropriate  for  purposes  other than  their  intended
purposes and that undue  reliance  should not be placed on any  forward-looking
statement.


                                      -8-
<PAGE>

                              CORPORATE STRUCTURE

NAME AND INCORPORATION

Compton  was  incorporated  by  articles  of  incorporation   pursuant  to  the
provisions of the BUSINESS  CORPORATIONS  ACT (Alberta) (the "ABCA") 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$450  million of 7 5/8% Senior Notes issued
by Compton Petroleum Finance Corporation,  its equity interest in Hornet Energy
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   issued  by  Compton   Petroleum   Corporation   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.


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


The consolidated financial statements include the accounts of Compton Petroleum
Corporation and all of its subsidiaries and partnerships.


                                      -9-
<PAGE>

                      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  2005,  progress  was  made on each of the  Company's  four  resource  plays
including the Plains Belly  River/Edmonton  group which  includes the Horseshoe
Canyon coalbed  methane,  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. 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 $564 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.

In  2006,  continued  progress  was  made  on the  development  of  each of the
Company's four resource plays.  Compton's  consolidated capital program of $526
million included drilling 342 gross (274 net) wells, replacing 348% of its 2006
production  at  an  all-in  finding,   development,  and  acquisition  cost  of
$8.84/boe, excluding change in future capital, and $13.56/boe, including change
in future capital.  The drilling program resulted in an average production rate
of 33,187 boe/d for the year and total proved plus probable reserves  increased
20% to 249 MMBoe as at December 31, 2006.

In 2007,  Compton  continued  to achieve  solid  proved plus  probable  reserve
additions at competitive finding and development costs in each of the Company's
core  areas.  Compton  successfully  completed  a 322  well  drilling  program,
replacing 192% of the Company's 2007 production at an all-in FD&A of $9.95/boe,
excluding change in future capital, and $12.86/boe,  including change in future
capital.  Compton's 2007 proved plus probable  reserves grew by 9% to 271 MMBoe
as at December  31,  2007.  During the year,  Compton  pursued the  strategy of
divesting  non-focus  assets  and the  redeployment  of the  proceeds  into the
Company's  focus area  natural  gas plays.  Compton  closed  non-core  property
divestments,  including  its  conventional  light oil property at Worsley,  for
total net  proceeds  of $303.1  million.  Compton  also added to its core areas
through a series of property  acquisitions  that totalled  approximately  $73.7
million and completed two  corporate  acquisitions,  Stylus Energy Inc. and WIN
Energy  Corporation,  which  significantly  expanded  its  presence in southern
Alberta and the Foothills at a total cost of $131.4 million.




                                     -10-
<PAGE>

                          DESCRIPTION OF THE BUSINESS

EXPLORATION AND PRODUCTION OPERATIONS

Compton's exploration, development and exploitation activities are concentrated
principally  in two core areas:  1) shallow gas resources  play,  targeting the
Plains Belly River and overlying  Edmonton  Horseshoe Canyon zones, and 2) deep
gas plays that include the Basal Quartz sands at Hooker, the Gething/Rock Creek
sands at Niton and  Caroline in central  Alberta,  and the  Foothills  stacked,
thrusted Upper Cretaceous Belly River play at Callum in the south.  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 the
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,
2007,  approximately  84% 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.

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.  Based on
plans for an annual drilling program of 500 to 700 gross wells, the Company has
over 10 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,  evidencing  the  Company's  ability to  successfully  grow
reserves and production from its extensive inventory of drilling locations.


                                     -11-
<PAGE>

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

Compton  engages  in oil and gas  exploration  and  development  in the WCSB in
Alberta,  Canada.  Compton's  focus is on the Deep Basin  portion of the Basin,
which extends from Northwest  Alberta and British Columbia to the United States
border.  In this  large  geographical  region,  Compton  pursues  two  types of
resource  plays. A shallow gas resource play,  targeting the Plains Belly River
and overlying  Edmonton  Horseshoe  Canyon zones,  and the three deep gas plays
that include the Basal Quartz sands at Hooker,  the Gething/Rock Creek sands at
Niton and Caroline in central  Alberta,  and the  Foothills  slacked,  thrusted
Upper Cretaceous Belly River play at Callum in the south.

SHALLOW GAS

The Plains Belly River and  overlying  Edmonton  Horseshoe  Canyon  shallow gas
zones cover more than 1,200 sections of Compton held land in southern  Alberta.
The entire 900 metre  gas-charged  section is comprised of multiple Belly River
sands,  silts,  shales, and coals,  overlain by the  Edmonton/Horseshoe  Canyon
coals that similarly include sands,  silts, and shales. In 2007 Compton drilled
a total of 226 wells through the Edmonton  Horseshoe Canyon targeting the Belly
River  section.  Going  forward,  Compton  expects  to  focus  on  downspacing,
development  drilling,  and  recompletions  in order to  establish  a  resource
manufacturing and processing model designed to maximize production.

PLAINS BELLY RIVER AND EDMONTON COAL BED METHANE

At December 31, 2007,  Compton was producing  approximately  55 mmcf/d from 630
Belly River and Edmonton coal bed methane  wells.  With 1,200 sections of land,
at four wells per section automatic downspacing, this land base translates to a
significant  multi-year,  low  risk  drilling  inventory  on  which to grow the
Company.

During  2007,  Compton  deployed  a  four  well  per  section  reduced  spacing
initiative for our Belly River drilling program.  Wherever possible,  Compton's
shallow  gas  wells  were  drilled  in  batches  in  areas  close  to  existing
infrastructure.   This  initiative  enabled  Compton  to  significantly  reduce
Compton's  2007 spud to rig release and rig release to  on-stream  times to 2.8
days and 99 days, respectively.  Drilling results at Compton's southern Alberta
Belly  River  play were 100%  successful  in 2007,  with  particularly  notable
advances in the Brant, south Hooker, Ghost Pine, and Vulcan areas. Such success
resulted  from the use of  Compton's  1,200  km(2) of  proprietary  3D seismic,
coupled with detailed geological  mapping,  which allowed us to model the Belly
River sands for consistent, repeatable success.


                                     -12-
<PAGE>

At Brant, Compton's 3-5-17-27W4M compressor station became fully operational in
November 2007,  providing  Compton the requisite  horsepower needed to bring on
eight new wholly owned Belly River wells. These wells were producing a combined
four  mmcf/d  at year  end.  The  average  production  rate of  these  wells is
approximately  double the Company's 30 day initial production rate of a typical
Belly River well.  Compton's 2007 drilling targeted longer term producing wells
such   as   Compton    Brant    00/07-05-017-27W4M/0    and   Compton    Silver
00/13-32-016-28W4M/2.  These  two  wells  are  producing  570  and  860  mcf/d,
respectively as at year end. In 2008, Compton intends to follow up with similar
drilling initiatives into south Hooker and south Brant.

In the Ghost Pine area, Compton expanded its 15-11-30-23W4M  compressor station
from  eight to 12 mmcf/d  in 2007.  A total of 62 Belly  River  and Horse  Shoe
Canyon coal wells are currently  producing 12 mmcf/d at Ghost Pine. Compton has
14 standing  gas wells that are  scheduled  to be tied-in in the first  quarter
2008, Compton has recently reprocessed its 3D seismic in this area, and in 2008
Compton  plans to use this seismic to replicate  the Ghost Pine Belly River gas
well  02/07-10-030-23W4M,  which had an initial production rate of 1,300 mcf/d,
and the  00/05-01-030-23W4/4  Coal Bed Methane  gas well,  which had an initial
production rate of 74 mcf/d.

Finally,  further south in the Vulcan area, Compton placed five Belly River gas
wells  drilled by Stylus  Energy Inc. on production in late 2007. In aggregate,
these  wells were  placed on  production  at 2.2  mmcf/d.  These  wells are the
southernmost Belly River gas wells producing in Alberta.

Compton's total compression  capacity for southern Alberta low pressure gas was
95 mmcf/d as at December 31, 2007.  Compton had 27,000  horsepower of installed
compression dedicated to the plays installed and running at year end 2007.

In 2008, Compton plans to drill 275 Belly River wells, focusing specifically on
the top tier prospects identified by its technical teams. Compton has allocated
approximately  $180  million  in its  budget  to this  area,  with  $5  million
ear-marked  specifically to continue with  identification of well locations and
licensing such that as industry conditions improve, Compton can readily ramp-up
activity.  Compton has estimated that approximately 40% of its 2008 Belly River
wells drilled in the latter part of the year will not come on production  until
early 2009 and will,  as a result,  be eligible to take  advantage of the lower
shallow gas royalty rates effective in Alberta for 2009.

Compton's  2008  southern  Alberta plans also include an eight well per section
pilot project. Additionally and following on Compton's Deep Basin deeper target
success as  described  below,  Compton will use extended  reach  drilling  with
multi-stage fracturing techniques in the pilot project.

DEEP BASIN

Compton has two Deep Basin gas plays:  the Basal Quartz sands at Hooker and the
Gething/Rock Creek sands at Niton and Caroline in central Alberta.

SOUTHERN ALBERTA: HOOKER

Discovered by Compton in 1999, the Basal Quartz sandstone pool at Hooker is the
southern  Alberta  extension  of the Lower  Cretaceous  Deep  Basin gas  trend.
Current production extends over five townships, and in 2007, Compton drilled 10
wells at Hooker.



                                     -13-
<PAGE>

In March 2008,  Compton  successfully  completed the first  horizontal  well in
southern  Alberta  at Niton  targeting  the Basal  Quartz  formation  utilizing
multi-stage fracturing technology.  The well at 9-17-17-29W4 was drilled with a
700 metre horizontal leg that flow tested at six mmcf/d and was tied-in shortly
thereafter. A second horizontal well is expected to be drilled at 15-30-16-29W4
and 15 follow-up locations have been identified.

While  Compton has been  employing  horizontal  drilling and  multi-stage  frac
technology  in the Niton area in central  Alberta with good  success,  the 9-17
well at Hooker is significant in that it  establishes  that this  technology is
applicable  to the  development  of the Hooker  Basal  Quartz  play in southern
Alberta. To date the Hooker play has been developed through drilling one to two
vertical wells per section.  Reservoir  modeling  indicates up to four vertical
wells per section may be necessary to fully develop the play. A horizontal well
could replace two to three vertical  wells,  eliminating the need for extensive
down-spacing in the area.

CENTRAL ALBERTA: NITON AND CAROLINE

The Niton area in central Alberta,  150 miles west of Edmonton,  is also in the
Lower  Cretaceous  Deep Basin fairway.  Compton's main targets are the Jurassic
Rock Creek and  Cretaceous  Gething,  analogous  to the Hooker pool in southern
Alberta. Proprietary exploration, development, and operational knowledge gained
by the Company in southern  Alberta has resulted in accelerated  growth of this
core area. In 2007, Compton drilled 35 wells at Niton and Caroline.

Compton  experienced  significant  drilling  success with  Compton's Rock Creek
horizontal  gas well  program at Niton in 2007.  The average  cost to drill and
complete a Niton horizontal gas well is approximately $4.5 million,  or roughly
two times the cost of a comparative vertical Rock Creek gas well. With a 30 day
initial  production  average of 5.0 mmcfe/d per well,  horizontal wells produce
about  four  times  that of a  comparative  vertical  well.  Compton's  average
horizontal  gas  well is 2,600  metres  deep  and has a 1,000  metre  open-hole
section.  Multiple  open-hole packers are set within the horizontal section and
three to four staged  hydraulic  fractures are completed.  At year end, Compton
had eight Niton  horizontal Rock Creek wells on production.  Six of these wells
were  gas  wells  and  two  were  oil  wells.  with  the  gas  wells  producing
approximately  16.2  mmcfe/d in  aggregate  and the two oil wells  producing  a
combined 153 boe/d.

To date in 2008 Compton has drilled two  additional  horizontal  wells at Niton
and a third well is being  drilled  in March  2008.  The first well  tested 3.0
mmcf/d and most  recently,  the well at  4-27-52-17W5  completed  at the end of
February  2008 flow  tested at 11  mmcf/d.  The third well is  scheduled  to be
completed  in  March  2008.  Production  from  these  wells  will  be  facility
constrained  pending the  completion  of additional  compression  and gathering
lines.  This work is scheduled for  completion by the end of March 2008 barring
any delay  resulting  from an early spring  break-up.  A total of 10 additional
locations are planned for this area in 2008.

In 2008,  Compton's  Niton  budget  plans for 15  horizontal  wells  using this
multi-stage  frac  technology.  Last  year's  focus by a number  of  producers,
including  Compton,  targeted the Compton  discovered  Edson Rock Creek P pool.
Following the Niton Rock Creek  successes,  Compton  posted and acquired a 100%
interest  in 12 sections  of mineral  rights on a second Rock Creek  discovery.
Late in 2007, Compton drilled Edson 00/01-31-052-16W5M/0 discovery well on this
block of land.  This well was  successful  and is  currently  producing  at 3.5
mmcfe/d.

All major compression  equipment has been ordered for this play,  Compton plans
to have eight 100% working  interest  horizontal  wells on stream by the end of
May 2008.


                                     -14-
<PAGE>

For 2008 Compton has allocated  approximately  $135 million or 33% of its total
planned  capital  expenditures to its central  Alberta  resource play.  Compton
plans  to drill 48 wells in this  area,  with 13 of these  wells  slated  to be
horizontal.  The 2008 plan is to continue to  aggressively  drill  similar Rock
Creek plays and to transfer this multi-staged horizontal fracture technology to
other Compton-operated deep basin gas plays throughout Alberta.

FOOTHILLS

Compton's  Callum/Cowley  property  consists  of a  series  of over  pressured,
thrusted,  low  permeability  Belly  River sands in the  foothills  of southern
Alberta. A total of 15 exploratory wells have been drilled over the life of the
play.  Based  on  Compton's  initial  detailed  geological,   geophysical,  and
engineering  analysis of seismic,  cores,  well logs,  and 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.

In 2007,  Compton drilled a horizontal well targeting a specific group of sands
plus  intersecting  mapped  fracture  systems.  The well came on  production at
approximately 6.5 mmcf/d, without stimulation. Further reservoir and completion
work is planned on this well bore in 2008.

During the fourth quarter of 2007,  Compton  acquired WIN Energy Inc., a junior
oil and gas company that was active on lands immediately adjacent to Compton's.
This  acquisition  added 68,000 gross (53,600 net) acres of undeveloped land in
the Cowley area in southern  Alberta  prospective  for the thrusted Belly River
trend. As at December 31, 2007 Compton held  approximately  239 net sections of
high impact exploration lands at Callum and Cowley.

With  Compton's  acquisition of WIN Energy Inc., it also acquired 55 kilometres
of 2D seismic and a new 36 square mile 3D seismic survey surrounding  currently
producing wells. Using this seismic data, Compton plans to replicate its recent
horizontal well program at Callum in the Cowley area. In 2008, Compton plans to
drill four extended  reach  horizontal  wells.  These wells will be oriented to
intersect  the maximum  number of natural  fractures in the foothills gas play.
Each of these horizontal wells will use multi-stage  fracturing  techniques and
will be drilled  from  existing  pads to  minimize  our  environmental  impact.
Compton  plans to drill a total of nine wells in the Callum and Cowley  area in
2008.

Compton treats the southern Alberta Foothills region as a unique  environmental
eco-system.   In  conjunction  with  a  number  of  southern  Alberta  ranching
operations,  we are  completing a rangeland  health  assessment  that addresses
optimal ways to restore  these systems to their  natural  state.  This includes
funding of studies on native rough fescue grasses by the University of Alberta,
as well as working  closely  with both  industry  and  landowner  work  groups.
Surface impact on all proposed  wells are  anticipated to be minimized by using
existing drill pads or by selecting surface areas on sites previously disturbed
by the agriculture industry.

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 monthly indexed  contracts.
Approximately 10% of the Company's natural gas production in 2007 was committed
to aggregators,  compared to an average of 11% in 2006. The average  aggregator
price  realized  in 2007 was  $0.75/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.


                                     -15-
<PAGE>

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 ngls  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,   Energy  Resources  and
Conservation  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
2008.  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.

EMPLOYEES

As at December 31,  2007,  Compton had 197  full-time  employees in its Calgary
office and 56 full-time employees at field locations.

COMPETITIVE CONDITIONS

Competitive  conditions  affecting the oil and gas industry are described under
the  heading  "Competition"  in the  "Risk  Factors"  section  of  this  Annual
Information Form.



                                     -16-
<PAGE>

                                  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 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 generally accepted accounting principles, 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 is based upon the lenders'  estimate of the
value of the Company's proved reserves,  which determines the borrowing amount.
A reduction in the quantity or value of reserves may also  obligate  Compton to
make additional payments under the processing agreement with MPP.

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 it will be able to find and develop or acquire  additional  reserves at an
acceptable cost.


                                     -17-
<PAGE>

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, 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.


                                     -18-
<PAGE>

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 does Compton.

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


                                     -19-
<PAGE>

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.

PROPOSED CHANGES TO THE ALBERTA ROYALTY REGIME

On October 25, 2007, the Alberta government released a report entitled "The New
Royalty Framework"  ("NRF") containing  proposed changes to the Alberta royalty
regime  scheduled to come into effect on January 1, 2009. The proposed  changes
include an increase in the royalties  collected by the Alberta government and a
change  in the  royalty  structure  for  natural  gas and  conventional  oil by
adjusting  the  current  sliding  rate  formulae  that  are  price  and  volume
sensitive.  It is anticipated  that the changes proposed in the NRF will result
in Compton paying marginally increased royalty rates in Alberta.

It is not  possible  at this time to  determine  the full  impact of the NRF on
Compton's  financial  condition and operations.  There is no assurance that the
NRF will be implemented in the form, or on the schedule,  proposed.  If changes
are made to the NRF before it is implemented, such changes may create a royalty
regime that will impact Compton in a materially  different  manner,  and may be
more or less adverse to Compton, than the NRF as currently proposed.

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 Compton's 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." On June 22,
2007,  the KYOTO  PROTOCOL  IMPLEMENTATION  ACT  received  royal assent and was
implemented to ensure that Canada meets its global  climate change  obligations
under the Kyoto  Protocol  though a yearly  Climate Change Plan prepared by the
Minister of  Environment  which will set out measures by which Canada will meet
its obligations.  On March 10, 2008 the federal government  announced its plan,
"Turning  the  Corner -  Taking  Action  to Fight  Climate  Change"  to  reduce
greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. As Compton's
production  facilities  and other  operations and  activities  emit  greenhouse
gases,  this plan will  subject  Compton  to these  emissions  targets  and may
subject  the  Company to  legislation  that will  require  increasingly  strict
regulation with respect to the emissions of greenhouse gases.

Other evolving  environmental  legislation  and actions which could result in a
material adverse effect on Compton's financial condition are as follows:

     o    Canada's CLEAN AIR ACT - the Government of Canada  released the first
          reading  of  this  Act on  October  19,  2006;  however,  the  policy
          framework for the new  legislation has not been released and detailed
          targets,  timeframes and compliance  options have not yet been set by
          the federal  government.  Future federal  legislation may require the
          reduction  of  emissions  or  emissions  intensity  of the  Company's
          operations and facilities;

     o    Alberta's CLIMATE CHANGE AND EMISSIONS MANAGEMENT ACT (which has been
          in existence  since 2003,  but did not come into effect until July 1,
          2007)  has  outlined  emission  reduction  guidelines  which  require
          Alberta  facilities  emitting more than 100,000  tonnes of greenhouse
          gases a year to reduce their  emissions  intensity by 12%.  Companies
          have three ways in which to meet their reductions: (i) make operating
          improvements; (ii) purchase Alberta-based emissions offsets; or (iii)
          acquire fund credits by making  contributions  to the Climate  Change
          and Emissions Management Fund;


                                     -20-
<PAGE>

     o    ALBERTA'S 2008 CLIMATE STRATEGY:  RESPONSIBILITY/LEADERSHIP/ACTION  -
          on January 24, 2008, the Alberta  Government  announced a new climate
          change  action  plan  that is  intended  to cut  Alberta's  projected
          greenhouse  gas emissions in half by 2050. The plan focuses on carbon
          capture and storage,  consumer incentives for energy conservation and
          efficiency and greener energy production through increased investment
          in clean energy  technologies and incentives for the use of renewable
          and alternative energy sources; and

     o    Canada-Alberta  ecoENERGY  Carbon Capture and Storage Task Force - on
          March 8, 2007,  the  Government of Canada and the Province of Alberta
          announced the formation of this Task Force to recommend the best ways
          for Canada to  implement  technology  to capture  carbon  dioxide and
          store it deep  underground.  The final  report of this Task Force was
          released on January 31, 2008 which  recommends,  among other  things:
          (i)  incorporating  carbon  capture  and  storage  into  federal  and
          provincial  greenhouse gas  legislation;  (ii) allocating new funding
          into projects  through a  competitive  process;  and (iii)  targeting
          research to lower the cost of carbon capture technology.

Given the evolving  nature of climate change action and  regulation,  it is not
possible to predict the nature of future  legislation  with  respect to climate
change or the impact on the Company,  its operations and financial condition at
this time.

Compliance with such  legislation may 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.

                           STATEMENT OF RESERVES DATA

Compton's  interests in its major  natural gas and crude oil  properties  which
represents  96% of the  Company's  oil and  natural  gas  reserves,  have  been
evaluated in a report (the "MAJOR REPORT") as of December 31, 2007, prepared by
the independent  international  integrated petroleum engineering and geological
firm, Netherland,  Sewell & Associates,  Inc. ("NETHERLAND SEWELL").  Compton's
interest in the minor natural gas and crude oil properties  which  represent 4%


                                     -21-
<PAGE>

of the Company's  oil and natural gas reserves  have been  evaluated in a minor
report as of December 31, 2007, prepared  internally by Compton.  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 Major 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 Major  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 March 24, 2008. The information  being provided in this
statement has an effective date of December 31, 2007 and a preparation  date of
February 29, 2008.

The  Report  on  Reserves  Data by  Compton's  independent  qualified  reserves
evaluators in Form  51-101F2 and the Report of Management  and Directors on Oil
and Gas Disclosure in Form 51-101F3 are attached hereto as Schedule "A" and "B"
respectively.

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, 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, 2007

==================================================================================================================================
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                       9,015      8,501      502,312      411,193      9,182      6,498     1,968      1,674
Developed non-producing                     222        197       54,579       45,348      1,079        749        66         55
Undeveloped                               1,695      1,502      187,629      153,912      2,100      1,432       149        124
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                             10,933     10,199      744,520      610,454     12,362      8,679     2,183      1,853
PROBABLE                                  6,495      5,842      624,604      509,753      9,820      6,879       839        711
----------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE               17,427     16,042    1,369,124    1,120,208     22,182     15,558     3,022      2,563
==================================================================================================================================
</TABLE>
(1)  Numbers may not add due to rounding.
(2)  The solution and associated gas represents 2% of the Company's natural gas
     reserves and is therefore considered immaterial and is not broken out.


                                     -22-
<PAGE>

The tables set forth below  summarize  the  Company's  future net revenue as of
December 31, 2007, based on forecast prices and cost assumptions.

<TABLE>
<CAPTION>
SUMMARY OF FUTURE NET REVENUE AS OF DECEMBER 31, 2007 (FORECAST PRICES)

================================================================================================================================
RESERVES CATEGORY (1)                                                   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                           2,871,487     1,768,094      1,452,542       1,304,364     1,052,974      894,081
Developed non-producing                         383,001       228,951        182,516         160,474       122,947       99,404
Undeveloped                                   1,020,126       561,293        415,622         344,872       222,290      144,771
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                  4,274,614     2,558,337      2,050,680       1,809,710     1,398,212    1,138,255
PROBABLE                                      3,800,077     1,894,415      1,355,781       1,109,123       708,309      475,143
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                    8,074,691     4,452,752      3,406,461       2,918,833     2,106,520    1,613,398
================================================================================================================================
</TABLE>
(1)  Numbers may not add due to rounding.

<TABLE>
<CAPTION>
================================================================================================================================
RESERVES CATEGORY (1)                                                   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                           2,385,378     1,559,261      1,296,437       1,170,811       956,188      820,703
Developed non-producing                         312,596       195,123        157,460         139,416       108,604       89,271
Undeveloped                                     791,808       441,507        324,431         267,287       168,360      106,196
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                  3,489,782     2,195,891      1,778,327       1,577,515     1,233,151    1,016,171
PROBABLE                                      2,844,624     1,440,193      1,012,163         815,019       497,843      318,226
--------------------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                    6,334,406     3,636,084      2,790,490       2,392,534     1,730,995    1,334,397
================================================================================================================================
</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, 2007 (FORECAST PRICES)

======================================================================================================================
  RESERVES      REVENUE    ROYALTIES    OPERATING    DEVELOP-MENT    WELL       FUTURE NET   INCOME       FUTURE NET
  CATEGORY      ($000S)     ($000S)       COSTS      COSTS       ABANDON-MENT    REVENUE     TAXES         REVENUE
                                         ($000S)      ($000S)      COSTS(1)       BEFORE      ($000S)       AFTER
                                                                   ($000S)        INCOME                    INCOME
                                                                                  TAXES                     TAXES
                                                                                 ($000S)                   ($000S)
----------------------------------------------------------------------------------------------------------------------
<S>            <C>          <C>           <C>         <C>              <C>        <C>         <C>           <C>
Proved          9,479,950   1,779,099     3,045,606     318,386        62,245     4,274,614     784,832     3,489,782
Proved plus
probable       17,189,666   3,285,085     4,572,123   1,164,773        92,994     8,074,691   1,740,285     6,334,406
======================================================================================================================
</TABLE>
(1) Includes, at minimum, well abandonment costs (rather than total abandonment
and reclamation costs).


                                     -23-
<PAGE>

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

<TABLE>
<CAPTION>
======================================================================================================================
RESERVES CATEGORY                  PRODUCTION GROUP       FUTURE NET REVENUE BEFORE INCOME     UNIT VALUE(3) BEFORE
                                                           TAXES (DISCOUNTED AT 10%/YEAR)     INCOME TAX (DISCOUNTED
                                                                       ($000S)                     AT 10%/YEAR)

                                                                                                 ($/BBL - $/MCF)
----------------------------------------------------------------------------------------------------------------------
<S>                           <C>                         <C>                                  <C>
Proved                        Crude oil(1)                                  299,508                   $29.37
                              Natural gas and ngls(2)                     1,510,203                   $2.47
Proved plus probable          Crude oil(1)                                  446,473                   $27.83
                              Natural gas and ngls(2)                     2,472,361                   $2.21
======================================================================================================================
</TABLE>
(1)  Includes solution gas and related ngls.
(2)  Excludes solution gas and related ngls.
(3)  Unit values are based on net reserves.


PRICING ASSUMPTIONS

Future net revenue calculated using forecast prices and costs is based upon the
price assumptions set out below. Netherland Sewell incorporated price forecasts
which were the average of the December 31, 2007 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, 2007

====================================================================================================================================
  YEAR             CRUDE OIL             NATURAL GAS                      NGLS                     SULPHUR     INFLATION   EXCHANGE
                                                                                                                RATE(1)      RATE
            WTI CUSHING    EDMONTON      AECO C SPOT       PROPANE       BUTANE      PENTANES+    PLANT GATE     %/YEAR    $CDN/$US
             OKLAHOMA      PAR 40(0)    ($CDN/MMBTU)     ($CDN/BBL)    ($CDN/BBL)   ($CDN/BBL)    ($CDN/LT)
             ($US/BBL)       API
                          ($CDN/BBL)
------------------------------------------------------------------------------------------------------------------------------------
<C>         <C>            <C>           <C>              <C>           <C>         <C>           <C>           <C>        <C>
FORECAST
2008           $89.15       $88.48          $6.74           $53.64        $67.25      $91.04        $39.00        2.0%       1.00
2009           $85.58       $85.52          $7.48           $52.35        $65.02      $88.03        $29.17        2.0%       0.99
2010           $83.25       $83.88          $7.69           $51.53        $63.83      $86.41        $22.67        2.0%       0.98
2011           $80.99       $82.03          $7.80           $50.60        $62.46      $84.54        $22.84        2.0%       0.98
2012           $80.18       $81.16          $7.84           $50.17        $61.81      $83.66        $23.12        2.0%       0.98
2013           $79.85       $80.79          $8.04           $50.12        $61.53      $83.30        $23.40        2.0%       0.98
2014           $81.03       $81.99          $8.26           $50.89        $62.45      $84.55        $24.15        2.0%       0.98
2015           $82.24       $83.25          $8.46           $51.72        $63.39      $85.84        $24.92        2.0%       0.98
2016           $83.47       $84.49          $8.64           $52.53        $64.31      $87.11        $25.69        2.0%       0.98
2017           $85.16       $86.21          $8.84           $53.65        $65.62      $88.90        $26.50        2.0%       0.98
Thereafter       2.0%         2.0%           2.0%             2.0%          2.0%        2.0%          2.0%        2.0%       0.98
====================================================================================================================================
</TABLE>
(1)  Inflation rate for operating and capital costs.


The  weighted  average  realized  sales  price for  Compton  for the year ended
December  31, 2007 was  $6.33/Mcf  for natural gas,  $64.17/bbl  for crude oil,
$63.61/bbl for ngls, and $6.78/lt for sulphur.


                                     -24-
<PAGE>

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.

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

=======================================================================================================================
                                                   CRUDE OIL                                      NGLS
                                GROSS          GROSS     GROSS PROVED        GROSS        GROSS         GROSS PROVED
                                PROVED       PROBABLE    PLUS PROBABLE      PROVED       PROBABLE       PLUS PROBABLE
                                (MBBL)        (MBBL)         (MBBL)         (MBBL)        (MBBL)            (MBBL)
-----------------------------------------------------------------------------------------------------------------------
<S>                            <C>           <C>          <C>             <C>            <C>            <C>
December 31, 2006               19,999        9,234          29,233        11,189          7,879           19,068
Extensions                         164          456             620           479            865            1,344
Improved recovery                  104           28             132           133            155              288
Technical revisions              1,318       (3,620)         (2,302)          232            118              349
Discoveries                        122           77             199           458            189              647
Acquisitions                       612          319             931           774            629            1,403
Dispositions                    (9,581)           -          (9,581)         (172)           (14)            (186)
Production                      (1,805)           -          (1,805)         (731)             -             (731)
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2007               10,933        6,495          17,427        12,362          9,820           22,182
=======================================================================================================================
</TABLE>
(1)  Prepared by Management. Numbers may not add due to rounding.

<TABLE>
<CAPTION>
=======================================================================================================================
                                                   CRUDE OIL                                      NGLS
                                GROSS          GROSS     GROSS PROVED        GROSS        GROSS         GROSS PROVED
                                PROVED       PROBABLE    PLUS PROBABLE      PROVED       PROBABLE       PLUS PROBABLE
                                (MBBL)        (MBBL)         (MBBL)         (MBBL)        (MBBL)            (MBBL)
-----------------------------------------------------------------------------------------------------------------------
<S>                            <C>           <C>          <C>             <C>            <C>            <C>
December 31, 2006              686,838        502,260       1,189,098       1,557            714            2,271
Extensions                      29,980         89,284         119,264           -              -                -
Improved recovery               12,269         12,696          24,965           -              -                -
Technical revisions             14,235        (38,824)        (24,589)        705            126              830
Discoveries                     18,054         10,691          28,745           -              -                -
Acquisitions                    49,178         49,923          99,101           -              -                -
Dispositions                   (13,124)        (1,426)        (14,550)          -              -                -
Production                     (52,910)             -         (52,910)        (79)             -              (79)
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2007              744,520        624,604       1,369,124       2,183            839            3,022
=======================================================================================================================
</TABLE>
(1) Prepared by Management. Numbers may not add due to rounding.



                                     -25-
<PAGE>

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------------------
                                                                                         TOTAL RESERVES
                                                                            GROSS       GROSS PROBABLE    GROSS PROVED
                                                                            PROVED          (MBOE)       PLUS PROBABLE
                                                                            (MBOE)                           (MBOE)
-----------------------------------------------------------------------------------------------------------------------
<S>                                                                        <C>             <C>               <C>
December 31, 2006                                                          147,218         101,537           248,755
Extensions                                                                   5,640          16,202            21,841
Improved recovery                                                            2,282           2,299             4,581
Technical revisions                                                          4,627          (9,848)           (5,221)
Discoveries                                                                  3,589           2,048             5,637
Acquisitions                                                                 9,583           9,269            18,851
Dispositions                                                               (11,940)           (252)          (12,192)
Production                                                                 (11,434)              -           (11,434)
-----------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2007                                                          149,564         121,255           270,819
=======================================================================================================================
</TABLE>
(1)   Prepared by Management. Numbers may not add due to rounding.


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 in production within a two year timeframe.

The following table summarizes the Company's proved  undeveloped  reserves over
the past three years using  forecast  price and cost  assumptions by production
type.

<TABLE>
<CAPTION>
======================================================================================================================
                                                           TOTAL PROVED UNDEVELOPED
                                CRUDE OIL             NATURAL GAS                NGLS                  SULPHUR
          YEAR                   (MBBL)                  (MMCF)                 (MBBL)                  (MLT)
----------------------------------------------------------------------------------------------------------------------
<S>                             <C>                  <C>                       <C>                      <C>
          2007                      1,695                187,629                  2,100                   149
          2006                      3,220                174,999                  2,016                   115
          2005                      5,019                 84,333                  1,731                   118
======================================================================================================================
</TABLE>


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 in production by
the end of 2010.


                                     -26-
<PAGE>

The following table summarizes the Company's probable undeveloped reserves over
the past three years using  forecast  price and cost  assumptions by production
type.

<TABLE>
<CAPTION>
======================================================================================================================
                                                          TOTAL PROBABLE UNDEVELOPED
                                CRUDE OIL             NATURAL GAS                NGLS                  SULPHUR
          YEAR                   (MBBL)                  (MMCF)                 (MBBL)                  (MLT)
----------------------------------------------------------------------------------------------------------------------
<S>                             <C>                   <C>                     <C>                     <C>
          2007                      3,302                482,866                  4,685                   528
          2006                      5,533                420,522                  6,446                   526
          2005                      5,779                355,237                  5,646                   772
======================================================================================================================
</TABLE>


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.

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  reserves
categories set out below:

<TABLE>
<CAPTION>
UNDISCOUNTED DEVELOPMENT COSTS DEDUCTED IN ESTIMATING FUTURE NET REVENUES(1)

======================================================================================================================
YEAR                                                          PROVED                      PROVED PLUS PROBABLE
                                                       FORECAST PRICES AND                 FORECAST PRICES AND
                                                        COSTS/YEAR ($000S)                 COSTS/YEAR ($000S)
----------------------------------------------------------------------------------------------------------------------
<S>                                                    <C>                                <C>
   2008                                                       $191,081                            $297,416
   2009                                                        104,598                             338,215
   2010                                                         21,164                             254,466
   2011                                                          6,158                             162,108
   2012                                                          3,624                              61,308
   Remaining                                                    54,006                             144,254
----------------------------------------------------------------------------------------------------------------------
Total                                                         $380,631                          $1,257,767
======================================================================================================================
</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.
Compton does not expect that the costs of funding its capital expenditures will
have a material effect on the economics of the programs.



                                     -27-
<PAGE>

OTHER OIL AND GAS INFORMATION

OIL AND GAS PROPERTIES AND WELLS

The  following  table  summarizes  the  location  of  the  Company's  important
interests  as at December 31, 2007 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     NON-PRODUCING     PRODUCING NATURAL     NON-PRODUCING      TOTAL WELLS
                                              CRUDE OIL                              NATURAL GAS
                           OIL WELLS          WELLS((2))          GAS WELLS          WELLS((2))
                        GROSS      NET      GROSS     NET      GROSS      NET      GROSS     NET      GROSS     NET
----------------------------------------------------------------------------------------------------------------------
<S>                    <C>        <C>       <C>       <C>     <C>       <C>        <C>      <C>      <C>      <C>
ALBERTA
  South                  144        57        41       8       1,619     1,112      312      232      2,116    1,409
  Central                150        91        40       10        262       141      108       38        560      280
  Peace River Arch       245        95        49       21         96        39       40       17        430      172
BC                         1         -         2        -         44         3        6        1         53        4
----------------------------------------------------------------------------------------------------------------------
TOTAL WELLS              540       243       132       39      2,021     1,295      466      288      3,159    1,865
======================================================================================================================
</TABLE>
(1)  Numbers may not add due to rounding.
(2)  A portion  of the  non-producing  wells are wells  considered  capable  of
     production but which,  for a variety of reasons  including but not limited
     to a lack of  markets  and  lack  of  development,  cannot  be  placed  on
     production at the present time.


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, 2007.

<TABLE>
<CAPTION>
======================================================================================================================
AREA                                                                               GROSS ACRES         NET ACRES
----------------------------------------------------------------------------------------------------------------------
<S>                                                                              <C>                  <C>
British Columbia                                                                       25,344              4,082
Alberta                                                                             1,092,588            886,382
Saskatchewan                                                                            1,918              1,918
Manitoba                                                                                1,280              1,080
----------------------------------------------------------------------------------------------------------------------
TOTAL                                                                               1,121,130            893,462
======================================================================================================================
</TABLE>

Approximately 32,000 net acres of undeveloped land could expire by December 31,
2008. However,  the Company's 2008 exploration and development  activities will
defer the expiry of a portion of these lands.

FORWARD CONTRACTS

In 2007,  Compton's  realized average field price was $43.82/boe,  comprised of
$6.33/Mcf  for natural  gas and  $62.28/bbl  for  liquids.  In 2006,  Compton's
realized average field price was $44.65/boe, comprised of $6.32/Mcf for natural
gas and $59.09/bbl for liquids.

Compton's  natural gas  production is sold under a  combination  of longer term
contracts with  aggregators and short term daily or monthly indexed  contracts.
Approximately 10% of the Company's natural gas production in 2007 was committed
to aggregators.  The average  aggregator price realized was $0.75/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.  Natural gas liquids 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 60% of non-contracted
net 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  1,900 net well sites and  facilities is the sum of the
calculated  abandonment  and  reclamation  liabilities  adjusted for designated
status  as  an  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 10.8% was used in the fair value calculation.

Total asset retirement  costs, net of estimated salvage values, is estimated to
be $116 million or $12 million when  discounted  at 10%. The  undiscounted  ARO
associated  with pipelines and facilities is estimated to be $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 $7 million dollars in ARO
costs between 2008 and 2011.

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 2010.

CAPITAL EXPENDITURES

In 2007,  Compton incurred  approximately  $43 million of exploration costs and
$252 million of development costs. Additionally, approximately $109 million was
received  on proved  property  net  dispositions  and $28  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,
2007 and 2006.

<TABLE>
<CAPTION>
======================================================================================================================
                                      YEAR ENDED DECEMBER 31, 2007                    YEAR ENDED DECEMBER 31, 2006
                                    DEVELOPMENT          EXPLORATORY                DEVELOPMENT          EXPLORATORY
                                  GROSS      NET       GROSS      NET            GROSS       NET      GROSS       NET
----------------------------------------------------------------------------------------------------------------------
<S>                               <C>       <C>        <C>        <C>             <C>       <C>        <C>        <C>
Natural gas                        257       219        19         15              222       180        29         24
Crude oil                           24        13         1          1               50        34         6          5
Dry and abandoned                    4         4         6          5               17        14         3          3
----------------------------------------------------------------------------------------------------------------------
TOTAL                              285       236        26         21              289       228        38         32
----------------------------------------------------------------------------------------------------------------------
SUCCESS RATIO                                     97%                                             94%
======================================================================================================================
</TABLE>


In 2008,  the Company  expects to continue to focus its  resources  in Alberta,
Canada. Compton's overall objective for 2008 is the recognition of its unbooked
resource   potential.   The  Company  has  developed  a  $410  million  capital
expenditure plan for 2008, encompassing up to 350 gross wells.

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 2007 THREE MONTHS ENDED                   YEAR ENDED
                                           MARCH 31,       JUNE 30,      SEPTEMBER 30,    DECEMBER 31,   DECEMBER 31,
                                             2007            2007            2007             2007           2007
----------------------------------------------------------------------------------------------------------------------
<S>                                       <C>            <C>             <C>              <C>             <C>
Natural gas (MMcf/d)                            148           130             135              167             145
Natural gas (MMcf)                           13,277        11,859          12,413           15,361          52,910

Natural gas liquids (boe/d)(1)                2,705         1,714           2,231            2,239           2,221
Natural gas liquids (Mboe)(1)                   243           156             205              206             810

Crude oil (bbl/d)                             6,024         5,485           5,723            2,579           4,945
Crude oil (Mbbls)                               542           499             526              237           1,805

Total liquids (boe/d)                         8,729         7,199           7,954            4,818           7,166
Total liquids (Mboe)                            785           655             731              443           2,615

Total (boe/d)                                33,316        28,918          30,440           32,646          31,326
Total (Mboe)                                  2,998         2,632           2,800            3,003          11,434
======================================================================================================================
</TABLE>
(1)  Includes sulphur.


                                     -30-
<PAGE>

<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------------------
             PRODUCT TYPE                               FISCAL 2006 THREE MONTHS ENDED                    YEAR ENDED
                                        MARCH 31, 2006   JUNE 30,    SEPTEMBER 30, 2006  DECEMBER 31,    DECEMBER 31,
                                                           2006                              2006            2006
----------------------------------------------------------------------------------------------------------------------
<S>                                     <C>               <C>         <C>                 <C>            <C>
Natural gas (MMcf/d)                          142              137         142                 148            142
Natural gas (MMcf)                         12,750           12,462      13,024              13,604         51,840

Natural gas liquids (boe/d)(1)              2,843            2,692       2,656               2,642          2,707
Natural gas liquids (Mboe)(1)                 256              245         244                 243            988

Crude oil (bbl/d)                           7,575            7,129       6,593               5,958          6,809
Crude oil (Mbbls)                             682              649         607                 548          2,486

Total liquids (boe/d)                      10,418            9,821       9,249               8,600          9,516
Total liquids (Mboe)                          938              894         851                 791          3,474

Total (boe/d)                              34,029           32,645      32,843              33,245         33,187
Total (Mboe)                                3,063            2,971       3,022               3,058         12,114
======================================================================================================================
</TABLE>
(1)  Includes sulphur.


2008 PRODUCTION ESTIMATES

Production  volumes in 2008,  as estimated in the  Company's  reserve  forecast
before deduction of royalties, are set forth below.

<TABLE>
<CAPTION>
======================================================================================================================
         RESERVES CATEGORY(1)                CRUDE        NATURAL GAS         NGLS          SULPHUR         TOTAL
                                           OIL(BBL/D)       (MMCF/D)        (BBL/D)         (LT/D)         (BOE/D)
----------------------------------------------------------------------------------------------------------------------
<S>                                        <C>            <C>              <C>              <C>            <C>
PROVED
Developed producing                           2,648             129          2,218              207        26,553
Developed non-producing                          67              12            227                4         2,292
Undeveloped                                     145              19            254                -         3,592
----------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                  2,860             160          2,699              211        32,436
PROBABLE                                        538              24            487                3         5,080
----------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                    3,397             184          3,186              214        37,516
======================================================================================================================
</TABLE>
(1)  Numbers may not add due to rounding.  Based on estimates  only.  Variances
     may occur due to circumstances beyond Compton's control.


Compton's  property in Niton is estimated to have production volumes in 2008 of
8,439 boe/d which  represents  22.5% of the total 2008 production  estimate for
total proved plus probable reserves.



                                     -31-
<PAGE>

The Company's per unit results on a quarterly  basis for the periods  indicated
is set forth below.

<TABLE>
<CAPTION>
==========================================================================================================================
                                                        FISCAL 2007 THREE MONTHS ENDED                      YEAR ENDED
                                        MARCH 31, 2007     JUNE 30,     SEPTEMBER 30,    DECEMBER 31,      DECEMBER 31,
                                                             2007            2007            2007              2007
--------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>               <C>            <C>             <C>               <C>
NATURAL GAS ($/MCF)
Price                                        $7.24           $6.92           $5.23            $6.00             $6.33
Royalties                                    (1.52)          (1.35)          (1.26)           (1.32)            (1.36)
Operating costs(1)                           (1.30)          (1.34)          (1.22)             (1.44)          (1.33)
Transportation costs                         (0.11)          (0.11)          (0.11)           (0.11)            (0.11)
--------------------------------------------------------------------------------------------------------------------------
Netback                                      $4.31           $4.12           $2.64            $3.13             $3.53

NATURAL GAS LIQUIDS ($/BBL)(3)
Price                                       $49.49          $52.23          $51.21           $79.40            $58.05
Royalties                                   (12.61)         (12.10)         (12.32)          (16.34)           (13.39)
Operating costs(1)                           (7.79)          (8.01)          (7.32)           (8.61)            (7.97)
Transportation costs                         (2.57)          (2.67)          (2.54)           (2.63)            (2.60)
--------------------------------------------------------------------------------------------------------------------------
Netback                                     $26.52          $29.45          $29.03           $51.82            $34.09

CRUDE OIL ($/BBL)
Price                                       $58.13          $63.08          $66.09           $76.04            $64.17
Royalties                                    (9.91)         (10.76)         (11.27)          (12.80)           (10.92)
Operating costs(1)                          (12.74)         (12.79)         (14.78)          (15.70)           (13.72)
Transportation costs                         (2.57)          (2.67)          (2.54)           (2.63)            (2.60)
--------------------------------------------------------------------------------------------------------------------------
Netback                                     $32.91          $36.86          $37.50           $44.91            $36.93

TOTAL LIQUIDS ($/BBL)
Price                                       $55.45          $60.49          $61.91           $77.60            $62.28
Royalties                                   (10.75)         (11.08)         (11.56)          (14.44)           (11.68)
Operating costs(1)                          (11.21)         (11.65)         (12.69)          (12.41)           (11.94)
Transportation costs                         (2.57)          (2.67)          (2.54)           (2.63)            (2.60)
--------------------------------------------------------------------------------------------------------------------------
Netback                                     $30.92          $35.09          $35.12           $48.12            $36.06

TOTAL ($/BOE)
Price(2)                                    $46.98          $47.94          $38.56           $41.94            $43.82
Royalties                                    (9.55)          (8.86)          (8.61)           (8.86)            (8.98)
Operating costs(1)                           (8.68)          (8.92)          (8.72)           (9.17)            (8.88)
Transportation costs                         (1.16)          (1.16)          (1.15)            (.95)            (1.10)
--------------------------------------------------------------------------------------------------------------------------
Netback                                     $27.59          $29.00          $20.08           $22.96            $24.86
==========================================================================================================================
</TABLE>

(1)  A portion of our natural gas  production is associated  with our crude oil
     production,   additionally  the  production  of  natural  gas  liquids  is
     associated  with  our  natural  gas  production.  As a  result,  per  unit
     operating  costs for each product line reflect the  allocation  of certain
     common costs in this determination.
(2)  Includes third party processing fees, but not included in product pricing.
(3)  Includes sulphur.


                                     -32-
<PAGE>

<TABLE>
<CAPTION>
==========================================================================================================================
                                                        FISCAL 2006 THREE MONTHS ENDED                       YEAR ENDED
                                       MARCH 31, 2006     JUNE 30,      SEPTEMBER 30,     DECEMBER 31,      DECEMBER 31,
                                                            2006             2006             2006              2006
--------------------------------------------------------------------------------------------------------------------------
<S>                                     <C>               <C>            <C>             <C>               <C>
NATURAL GAS ($/MCF)
Price                                      $7.58           $5.86             $5.38            $6.48             $6.32
Royalties                                  (1.79)          (1.31)            (1.15)           (1.47)            (1.43)
Operating costs(1)                         (1.03)          (1.11)            (1.35)           (1.41)            (1.23)
Transportation costs                       (0.15)          (0.15)            (0.15)           (0.15)            (0.15)
--------------------------------------------------------------------------------------------------------------------------
Netback                                    $4.61           $3.29             $2.73            $3.45             $3.51

NATURAL GAS LIQUIDS ($/BBL)(3)
Price                                     $43.76          $54.38            $53.32           $42.94            $48.56
Royalties                                 (13.52)         (15.29)           (14.87)          (12.36)           (14.01)
Operating costs(1)                         (6.19)          (6.66)            (8.13)           (8.49)            (7.37)
Transportation costs                       (1.24)          (1.41)            (1.41)           (1.48)            (1.38)
--------------------------------------------------------------------------------------------------------------------------
Netback                                   $22.81          $31.02            $28.91           $20.61            $25.80

CRUDE OIL ($/BBL)
Price                                     $57.84          $71.89            $69.11           $53.39            $63.28
Royalties                                 (12.09)         (17.60)           (16.33)          (11.37)           (14.40)
Operating costs(1)                        (10.50)         (11.36)           (14.17)          (15.31)           (12.77)
Transportation costs                       (1.24)          (1.41)            (1.41)           (1.48)            (1.38)
--------------------------------------------------------------------------------------------------------------------------
Netback                                   $34.01          $41.52            $37.20           $25.23            $34.73

TOTAL LIQUIDS ($/BBL)
Price                                     $54.00          $67.09            $64.58           $50.18            $59.09
Royalties                                 (12.48)         (16.97)           (15.91)          (11.68)           (14.29)
Operating costs(1)                         (9.32)         (10.07)           (12.43)          (13.21)           (11.23)
Transportation costs                       (1.24)          (1.41)            (1.41)           (1.48)            (1.38)
--------------------------------------------------------------------------------------------------------------------------
Netback                                   $30.96          $38.64            $34.83           $23.81            $32.19

TOTAL ($/BOE)
Price(2)                                  $48.58          $45.37            $42.03           $42.60            $44.65
Royalties                                 (11.29)         (10.59)            (9.42)           (9.54)           (10.21)
Operating costs(1)                         (7.15)          (7.69)            (9.34)           (9.71)            (8.47)
Transportation costs                       (1.00)          (1.05)            (1.04)           (1.05)            (1.04)
--------------------------------------------------------------------------------------------------------------------------
Netback                                   $29.14          $26.04            $22.23           $22.30            $24.93
==========================================================================================================================
</TABLE>
(1)  A portion of our natural gas  production is associated  with our crude oil
     production,   additionally  the  production  of  natural  gas  liquids  is
     associated  with  our  natural  gas  production.  As a  result,  per  unit
     operating  costs for each product line reflect the  allocation  of certain
     common costs in this determination.
(2)  Includes third party processing fees, but not included in product pricing.
(3)  Includes sulphur.
(4)  Certain  amounts have been  reclassified  to conform  with current  period
     presentation.


                                     -33-
<PAGE>

The following  table  indicates  average daily gross  production from important
areas in respect of Compton's assets for the year ended December 31, 2007:

<TABLE>
<CAPTION>
                                              CRUDE OIL        NATURAL GAS          NGLS             TOTAL
                                               (BBLS/D)          (MCF/D)          (BBLS/D)          (BOE/D)

<S>                                         <C>              <C>                <C>              <C>
Southern Alberta                                  340            79,109            1,050            14,575
Central Alberta                                 1,086            50,855              919            10,480
Peace River Arch                                3,418            14,435              182             6,007
Other                                             101               561               70               264
                                           ----------        ----------        ---------        ----------
                                                4,945           144,960            2,221            31,326
                                           ==========        ==========        =========        ==========
</TABLE>

                                   DIVIDENDS

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

                               CAPITAL STRUCTURE

Compton is  authorized  to issue an  unlimited  number of common  shares and an
unlimited number of preferred shares,  of which  129,317,421  common shares are
issued and outstanding as fully paid and  non-assessable  share as at March 25,
2008. No preferred  shares are issued and outstanding as at March 25, 2008. 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.  Holders of preferred  shares do not hold voting rights.
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.


                                     -34-
<PAGE>

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.  The Rights Plan was ratified by and
extended to June 3, 2009 by  shareholders  at the annual and special meeting of
Compton shareholders held on May 10, 2006.

                             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>
2007
   January                     $11.42                   $9.57                         492,536
   February                    $11.40                  $10.54                         322,984
   March                       $11.81                  $10.22                         493,522
   April                       $12.27                  $11.38                         346,252
   May                         $13.19                  $11.92                         458,374
   June                        $12.65                  $10.58                         485,356
   July                        $11.50                  $10.45                         799,383
   August                      $10.96                   $9.40                         596,761
   September                   $10.01                   $9.17                         359,196
   October                      $9.40                   $8.20                         487,587
   November                     $8.30                   $7.40                         519,224
   December                     $9.26                   $7.87                         420,086

2008
   January                      $9.79                   $8.79                         409,255
   February                    $11.80                   $9.75                         536,633
   March 1-25                  $12.05                  $11.03                         427,023
==============================================================================================================
</TABLE>



                                     -35-
<PAGE>

                             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 ABCA  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 ABCA.  To the extent that  conflicts  of
interest  arise,  such  conflicts  will be  resolved  in  accordance  with  the
provisions  of the  ABCA 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 that is the direct or indirect beneficial owner of, or who exercised
control or direction  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.

            CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS

None of those  persons who are  directors or officers of Compton is or has been
within  the  past 10  years,  a  director,  chief  executive  officer  or chief
financial officer of any company,  including  Compton,  that, while such person
was acting in that capacity,  was the subject of a cease trade or similar order
or an order  that  denied  company  access to any  exemption  under  securities
legislation,  for a period  of more than 30  consecutive  days,  or after  such
persons ceased to be a director,  chief  executive  officer or chief  financial
officer of the company was the subject of a cease trade or similar  order or an
order  that  denied  the  company  access  to any  exemption  under  securities
legislation, for a period of more than 30 consecutive days, which resulted from
an event that occurred while acting in such capacity.

In addition,  none of those persons who are directors or executive  officers of
Compton or a shareholder  holding a sufficient  number of securities of Compton
to affect  materially  the control of the  Company,  is, or has been within the
past 10 years,  a  director  or  executive  officer of any  company,  including
Compton,  that while such person was acting in that capacity,  or within a year
of that person ceasing to act in that capacity became bankrupt, made a proposal
under any legislation relating to bankruptcy or insolvency or was subject to or
instituted any proceedings, arrangement or compromise within creditors or had a
receiver, receiver manager or trustee appointed to hold assets.

None of the persons who are  directors or officers of Compton have been subject
to any  penalties  or  sanctions  imposed  by a court  relating  to  securities
legislation  or by a  securities  regulatory  authority  or has entered  into a
settlement agreement with a securities  regulatory authority or been subject to
any other  penalties or sanctions  imposed by a court or  regulatory  body that
would likely be  considered  important  to a  reasonable  investor in making an
investment decision.



                                     -36-
<PAGE>

                               MATERIAL CONTRACTS

Except for contracts  entered into in the ordinary course of business,  Compton
has not entered into any material  contracts within the last financial year, or
before  the last  financial  year  which are  still in  effect,  other  than as
follows:  an 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.  On April 4,  2006,  Compton
Petroleum Finance  Corporation issued an additional  U.S.$150 million aggregate
principal  amount of senior term notes under this  Indenture  on the same terms
and  conditions  as the senior terms notes  issued on November  22,  2005.  The
senior notes are guaranteed by Compton and the initial subsidiary guarantors.

Compton has a $500 million (as at December 31, 2007) authorized  senior secured
credit facility with a syndicate of banks. The credit facility is available for
general  corporate  purposes.  The  facility  reaches  term on July 2, 2008 and
matures  366 days  later on July 3, 2009 at which  time must be repaid in full.
Compton  currently  intends to request that the term and maturity of the credit
facilities be extended, subject to the bank lenders' consent to such requests.

                    LEGAL PROCEEDINGS AND REGULATORY ACTIONS

To the knowledge of the Company, there are no legal proceedings material to the
Company  to which  the  Company  is or was a party  to or of  which  any of its
properties is or was the subject of, during the financial  year ended  December
31,  2007  nor are  there  any such  proceedings  known  to the  Company  to be
contemplated.

During the year ended  December  31,  2007,  there  were no: (i)  penalties  or
sanctions  imposed  against  the  Company  by a court  relating  to  securities
legislation  or  by  a  securities  regulatory  authority;  (ii)  penalties  or
sanctions  imposed by a court or regulatory body against the Company that would
likely be considered important to a reasonable investor in making an investment
decision,  or (iii)  settlement  agreements  the Company  entered into before a
court  relating  to  securities  legislation  or with a  securities  regulatory
authority.

                              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  common  shares.  As at the date hereof,  principals  of Netherland
Sewell personally  disclosed in certificates of qualification that they neither
held, nor expected to receive, any of the Company's outstanding common shares.



                                     -37-
<PAGE>

                                    RATINGS

Standard & Poor's Rating Services ("S&P") and Moody's  Corporation  ("MOODY'S")
have rated Compton  Petroleum  Finance  Corporation's  U.S. $450 million 7 5/8%
Senior  Notes as B and B2  respectively,  as at December  31,  2007. 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.

                             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 12,
2008 at 3:30 pm. (Calgary time) in the Historical  Ballroom on the Fourth 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,  other than Peter Seldin, 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 & Chief Executive Officer of 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.


                                     -38-
<PAGE>

<TABLE>
<CAPTION>
=======================================================================================================================
NAME AND MUNICIPALITY OF RESIDENCE                          PRINCIPAL OCCUPATION                            DIRECTOR
                                                                                                             SINCE
-----------------------------------------------------------------------------------------------------------------------
<S>                                 <C>                                                                     <C>
Mel F. Belich, Q.C.                 Chairman,   Compton  Petroleum  Corporation.   Mr. Belich  has  been      1993
Calgary, AB, Canada                 Chairman and  President of each of Enbridge  International  Inc. and
                                    Enbridge  Technology Inc., and a director of numerous  affiliates of
                                    Enbridge  Inc., a pipeline  company,  including  those in Europe and
                                    Latin America.

                                    Mr. Belich is the Chairman of the Board of directors of Compton, the
                                    Chairman of the Corporate  Governance  Committee and the Chairman of
                                    the Special Committee of Independent Members of the Board.
-----------------------------------------------------------------------------------------------------------------------
Ernie G. Sapieha, C.A.              President & Chief Executive Officer of the Company.                       1993
Calgary, AB, Canada
-----------------------------------------------------------------------------------------------------------------------
J. Stephens Allan,                  Consultant  to RSM  Richter  LLP,  one of  the  largest  independent      2007
F.C.A., ICD.D                       accounting,  business  advisory,  and  consulting  firms in  Canada.
Calgary, AB, Canada                 Mr. Allan  has 38 years of  experience  as a  Chartered  Accountant,
                                    which includes extensive  experience in corporate  restructuring and
                                    complex corporate litigation matters. He was awarded an FCA in 1992.

-----------------------------------------------------------------------------------------------------------------------
Irvine J. Koop, P. Eng.             Independent  businessman  and prior  thereto  was the  Chairman  and      1996
Calgary, AB, Canada                 Chief   Executive   Officer  of  IKO  Resources  Inc.,  a  petroleum
                                    consulting  firm. Mr. Koop was the President and CEO,  Pipelines and
                                    Midstream of Westcoast  Energy Inc., an energy products and services
                                    company  (acquired  by Duke  Energy  Company),  and  was the  former
                                    president and CEO of Numac Energy,  an oil and gas company (acquired
                                    by Anderson Exploration).

                                    Mr. Koop  is the  Chairman  of the  Human  Resources,  Compensation,
                                    Environmental, Health and Safety Committee.
-----------------------------------------------------------------------------------------------------------------------
John W. Preston                     Independent  Businessman  and prior  thereto,  an Account  Executive      1993
Calgary, AB, Canada                 with Sun Microsystems of Canada Inc., a computer company.
-----------------------------------------------------------------------------------------------------------------------
Peter K. Seldin                     Founder and Managing Member of Centennial  Energy Partners,  L.L.C.,      2008
New York, New York, United States   general partner of four energy-sector  investment  partnerships that
                                    invest  in oil and gas  producers  and  oilfield  service  companies
                                    worldwide.  Mr. Seldin is also a director of Tesco  Corporation,  an
                                    oilfield equipment and services company.

-----------------------------------------------------------------------------------------------------------------------
Jeffrey T. Smith, P. Geol.          Independent  Businessman and prior thereto,  Chief Operating Officer      1999
Calgary, AB, Canada                 of Northstar Energy  Corporation,  an oil and gas company  (acquired
                                    by Devon Energy).

                                    Mr. Smith is Chairman of the  Engineering,  Reserves and  Operations
                                    Committee.
-----------------------------------------------------------------------------------------------------------------------
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  (acquired by
                                    Husky Energy Inc.).

                                    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 10, 2008 relating to the Annual
Meeting  of  Shareholders  to be held  on May  12,  2008,  which  sections  are
incorporated by reference into this Annual Information Form.


                                      -39-
<PAGE>

OFFICERS

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

<TABLE>
<CAPTION>
======================================================================================================================
NAME AND MUNICIPALITY OF RESIDENCE              PRINCIPAL OCCUPATION
----------------------------------------------------------------------------------------------------------------------
<S>                                             <C>
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.
Calgary, Alberta

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

Marc R. Junghans, P. Geol.                      Vice President Exploration of the Company.
Calgary, Alberta
======================================================================================================================
</TABLE>

As at March  25,  2008,  the  directors  and  officers  of  Compton  as a group
beneficially  owned or controlled,  directly or indirectly,  13,789,135  common
shares  of  Compton,   representing  approximately  10.7%  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.

                 AUDIT, FINANCE AND RISK COMMITTEE INFORMATION

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

COMPOSITION OF THE AUDIT, FINANCE AND RISK COMMITTEE

Chairman: John A. Thomson
Members: J. Stephens Allan, Mel F. Belich, Irvine J. Koop, John W. Preston,
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.  Allan, Belich,  Koop, Preston,  Smith, and Thomson have been
determined to be independent directors.

Mr.  Thomson is considered  to be a "financial  expert," as defined in National
Instrument 52-110,  "Audit Committees," ("NI 52-110") issued by the CSA, 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 NI 52-110,  due to their  experience  in  various  management  positions  or
qualification as a Chartered Accountant.




                                     -40-
<PAGE>

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   engagements
(including separate audits of subsidiary entities,  financings,  and regulatory
reporting  requirements),  tax and other  services  in the fiscal  years  ended
December 31, 2007 and 2006 were as follows:

================================================================================
TYPE OF SERVICE                           FISCAL 2007              FISCAL 2006
--------------------------------------------------------------------------------
Financial statement audit                     $517,000               $578,610
Internal controls audit                        454,000                690,675
Audit related                                   43,000                 69,220
Tax                                                  -                  8,795
Other non-audit                                 37,699                 34,740
--------------------------------------------------------------------------------
Total                                       $1,051,699             $1,382,040
================================================================================

Fees in respect of the  fiscal  2007  Internal  Controls  Audit  related to the
review of  Compton's  United  States  Sarbanes-Oxley  Act of 2002,  and similar
Canadian regulatory, compliance. The audit related fees incurred in fiscal 2007
related  to  Compton  Petroleum  Finance  Corporation's  oil and  gas  property
dispositions.  The fees for  other  non-audit  services  in  fiscal  2007  were
incurred to translate the Company's quarterly and annual reports into French.

Fees in respect of the  fiscal  2006  Internal  Controls  Audit  related to the
review of Compton's United States  Sarbanes-Oxley  Act of 2002 compliance.  The
audit related fees  incurred in fiscal 2006 related to the  Company's  U.S.$150
million  Senior Notes  offering in March 2006. Tax fees incurred in fiscal 2006
related to the review of tax forms. Fees for other non-audit services in fiscal
2006  related  primarily  to  services  incurred  to  translate  the  Company's
quarterly and annual reports into French.

The Audit,  Finance and Risk Committee of the Company considered these fees and
determined that they were reasonable and do not impact the  independence of the
Company's auditors.  Further, such Committee determined that in order to ensure
the continued  independence  of the auditors,  only limited  non-audit  related
services  would be provided to the  Company by Grant  Thornton  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 $25,000 per quarter.


                          TRANSFER AGENT AND REGISTRAR

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



                                     -41-
<PAGE>

                             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 10,
2008,  relating to the Annual and Special Meeting of Shareholders to be held on
May  12,  2008.  Additional  financial  information  is  also  provided  in the
consolidated  financial  statements  and MD&A of the Company for the year ended
December 31, 2007,  included in the  Company's  2007 Annual  Report.  Copies of
these and other  documents  relating to Compton  have been filed with the CSA's
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





                                     -42-
<PAGE>


                                   SCHEDULE A


[GRAPHIC OMITTED -- LOGO]
Netherland, Sewell &
Associates, Inc.


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



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

     1.   We have evaluated the Company's major properties  reserves data as at
          December 31, 2007. The reserves data are estimates of proved reserves
          and probable  reserves and related  future net revenue as at December
          31, 2007,  estimated using forecast prices and costs.

     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, 2007, and
          identifies the respective portions thereof that we have evaluated and
          reported on to the Company's board of directors:

<TABLE>
<CAPTION>
                                                                      Net Present Value of Future Net Revenue
                                                 Location of          (before Canadian federal income taxes,
                           Description and         Reserves                   10% discount rate) (MC$)
 Independent Qualified   Preparation Date of  (Country or Foreign  ---------------------------------------------
  Reserves Evaluator      Evaluated Report      Geographic Area)    Audited    Evaluated    Reviewed       Total
------------------------ -------------------- -------------------- --------- ------------ ------------ ---------
<S>                      <C>                   <C>                  <C>        <C>          <C>        <C>
Netherland, Sewell &
Associates, Inc.          February 29, 2008          Canada           nil      2,748,246       nil      2,748,246
</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
          did not evaluate.

     6.   We have  no  responsibility  to  update  our  report  referred  to in
          paragraph  4  for  events  and  circumstances   occurring  after  its
          respective preparation date.

     7.   Because the  reserves  data are based on judgments  regarding  future
          events,  actual results will vary and the variations may be material.
          However,  any  variations  should  be  consistent  with the fact that
          reserves  are  categorized  according  to the  probability  of  their
          recovery.


                                      -43-
<PAGE>

[GRAPHIC OMITTED -- LOGO]
Netherland, Sewell &
Associates, Inc.


Executed as to our report referred to above:


                                       NETHERLAND, SEWELL & ASSOCIATES, INC.
                                       Dallas, Texas, USA
                                       March 24, 2008


                                       By:  /s/ C.H. (Scott) Rees III, P.E.
                                            ------------------------------------
                                            C.H. (Scott) Rees III, P.E.
                                            Chairman and Chief Executive Officer


RCB:MBB

-------------------------------------------------------------------------------
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The digital document is intended to be  substantively  the same as the original
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document,  the  original  document  shall  control  and  supersede  the digital
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-------------------------------------------------------------------------------


                                     -44-
<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 are estimates of proved reserves and
probable  reserves  and related  future net revenue as at  December  31,  2007,
estimated using forecast prices and costs.

An independent  qualified  reserves  evaluator has evaluated (in respect of the
Company's  major  properties)  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:

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

     (b)    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

     (c)    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:

     (a)    the content and filing with  securities  regulatory  authorities of
            Form  51-101F1  containing  reserves  data  and  other  oil and gas
            information;

     (b)    the filing of Form 51-102F2 which is the report of the  independent
            qualified reserves evaluator on the reserves data; and

     (c)    the content and filing of this report.




                                     -45-
<PAGE>

Because the  reserves  data are based on  judgments  regarding  future  events,
actual  results  will vary and the  variations  may be material.  However,  any
variations  should be consistent  with the fact that  reserves are  categorized
according to the probability of their recovery.

(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,            Chairman of the Board
Reserves and Operations Committee



March 25, 2008




                                     -46-
<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;


                                     -47-
<PAGE>

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;

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;


                                     -48-
<PAGE>

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:

      (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;


                                     -49-
<PAGE>

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;

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,


                                     -50-
<PAGE>

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

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

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

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

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

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

(D)   ADDITIONAL DUTIES AND RESPONSIBILITIES

1.    review the  appointments  of 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;


                                     -51-
<PAGE>

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.


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.


                                     -52-
<PAGE>

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.

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.


                                     -53-
<PAGE>

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.






                                     -54-
<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;


-----------------
(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.


                                     -55-
<PAGE>

(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 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.





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(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.





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