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


================================================================================






                                 [LOGO OMITTED]

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




                             ANNUAL INFORMATION FORM
                      For the Year Ended December 31, 2006
















                                 March 26, 2007




================================================================================

<PAGE>

                                TABLE OF CONTENTS

                                                                           Page
                                                                           ----

ABBREVIATIONS AND CONVERSION FACTORS.........................................2
DEFINITIONS..................................................................3
ADVISORIES...................................................................8
CORPORATE STRUCTURE..........................................................8
GENERAL DEVELOPMENT OF THE BUSINESS..........................................9
DESCRIPTION OF THE BUSINESS.................................................10
RISK FACTORS................................................................14
STATEMENT OF RESERVES DATA..................................................18
PRICING ASSUMPTIONS.........................................................22
RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE...............23
ADDITIONAL INFORMATION RELATING TO RESERVES DATA............................25
OTHER OIL AND GAS INFORMATION...............................................27
DIVIDENDS...................................................................33
CAPITAL STRUCTURE...........................................................33
MARKET FOR SECURITIES.......................................................34
CONFLICTS OF INTEREST.......................................................34
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.................34
MATERIAL CONTRACTS..........................................................35
INTERESTS OF EXPERTS........................................................35
RATINGS ....................................................................35
DIRECTORS AND OFFICERS......................................................36
AUDIT, FINANCE AND RISK COMMITTEE INFORMATION...............................38
COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE............................38
EXTERNAL AUDITOR FEES.......................................................38
TRANSFER AGENT AND REGISTRAR................................................39
ADDITIONAL INFORMATION......................................................39
SCHEDULE A..................................................................40
SCHEDULE B..................................................................44
SCHEDULE C..................................................................46




                                     - 1 -
<PAGE>

                      ABBREVIATIONS AND CONVERSION FACTORS

ABBREVIATIONS

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

"bbl" means barrel;

"bbl/d" means barrels per day;

"bbls" means barrels;

"Bcf" means billion cubic feet;

"boe" means barrels of crude oil equivalent;

"boepd" or "boe/d" means barrels of crude oil equivalent per day;

"bopd" means barrels of crude oil per day;

"lt" means long ton;

"km" means kilometres;

"km(2)" means square kilometres;

"Mbbls" means thousand barrels;

"Mboe" means thousand barrels of crude oil equivalent;

"Mcf" means thousand cubic feet;

"mi" means miles;

"mi(2)" means square miles;

"MMbbls" means million barrels;

"MMBoe" means million barrels of crude oil equivalent;

"MMbtu" means million British thermal units;

"MMcf" means million cubic feet;

"Mcfe" means thousand cubic feet equivalent;

"MMcfd" or "MMcf/d" means million cubic feet per day;

"Mlt" means thousands of long tons;

"Mstb" means thousand stock tank barrels; and

"ngls" means natural gas liquids.




                                     - 2 -
<PAGE>

CONVERSION FACTORS

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


-------------------------------------------------------------------------------
            TO CONVERT FROM                  TO                  MULTIPLY BY
-------------------------------------------------------------------------------
     cubic feet                         cubic metres                  0.028
     boe                                Mcfe                          6.000
     cubic metres of gas                cubic feet                   35.490
     bbls                               cubic metres                  0.159
     cubic metres of oil                bbls                          6.289
     feet                               metres                        0.305
     metres                             feet                          3.281
     miles                              kilometres                    1.609
     kilometres                         miles                         0.621
     acres                              hectares                      0.405
     hectares                           acres                         2.471
-------------------------------------------------------------------------------


                                   DEFINITIONS

The following  terms,  when used in this document,  have the following  meanings
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.

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

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

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

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

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

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

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

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

                                      - 3 -
<PAGE>

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

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

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

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

        (d)   provide improved recovery systems.

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

"EUB" means the Alberta Energy and Utilities Board.

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

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

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

        (c)   dry hole contributions and bottom hole contributions;

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

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

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

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

                                      - 4 -
<PAGE>

localized  geological  features,  in contrast to broader terms such as "basin,"
"trend," "province," "play," or "area of interest".

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

        (a)   generally  accepted as being a  reasonable  outlook of the future;
              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 constant prices
and costs or forecast prices and costs.

"GROSS" means:

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

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

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

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

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

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

"NET" means:

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

                                      - 5 -
<PAGE>

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

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

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

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

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

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

"PROPERTY" includes:

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

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

        (c)   an agreement with a foreign  government or authority under which a
              reporting  issuer  participates  in the operation of properties or
              otherwise  serves  as  producer  of the  underlying  reserves  (in
              contrast to being an independent  purchaser,  broker,  dealer,  or
              importer).

A property  does not include  supply  agreements or contracts  that  represent a
right to purchase, rather than extract, oil or gas.

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

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

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

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

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

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

"RESERVES" are estimated  remaining  quantities of oil, natural gas, and related
substances anticipated to be recoverable from known accumulations,  from a given
date forward,  based on (a) analysis of drilling,  geological,  geophysical  and
engineering  data;  (b) the use of  established  technology;  and (c)  specified
economic conditions,

                                      - 6 -
<PAGE>

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

"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 natural gas dissolved in crude oil.

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

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

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

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

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

                                      - 7 -
<PAGE>

                                   ADVISORIES

USE OF BOE EQUIVALENTS

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

FORWARD LOOKING STATEMENTS

Certain  information  regarding the Company contained herein constitutes forward
looking  statements under the meaning of applicable  securities laws,  including
the United States  Private  Securities  Litigation  Reform Act of 1995.  Forward
looking statements include estimates, plans, expectations,  opinions, forecasts,
projections,  guidance,  or other  statements  that are not  statements of fact,
including statements regarding (i) cash flow, 2007 production estimates, reserve
estimates,  capital  expenditures,  2007 drilling program, tax estimates,  total
future net revenue, pricing assumptions,  abandonment and reclamation costs, and
(ii) other risks and  uncertainties  described  from time to time in the reports
and filings made by Compton with  securities  regulatory  authorities.  Although
Compton  believes  that  the  expectations  reflected  in such  forward  looking
statements are reasonable,  it can give no assurance that such expectations will
prove to have been  correct.  There are many  factors  that could cause  forward
looking statements not to be correct, including risks and uncertainties inherent
in the Company's  business.  These risks include,  but are not limited to: crude
oil and natural gas price volatility,  exchange rate fluctuations,  availability
of  services  and  supplies,   operating   hazards  and   mechanical   failures,
uncertainties  in the estimates of reserves and in projection of future rates of
production and timing of development expenditures,  general economic conditions,
and the actions or inactions of third-party operators, and other risks set forth
in the "Risk Factors" section of this Annual  Information Form.  Compton may, as
considered  necessary in the  circumstances,  update or revise  forward  looking
information,  whether  as  a  result  of  new  information,  future  events,  or
otherwise.  The Company's forward looking statements are expressly  qualified in
their entirety by this cautionary statement.


                               CORPORATE STRUCTURE

NAME AND INCORPORATION

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

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

Effective January 31, 2001, a general  partnership  called Compton Petroleum was
formed  under the laws of  Alberta.  Compton  Petroleum  Corporation  and Hornet
Energy Ltd., a wholly-owned subsidiary of Compton Petroleum Finance Corporation,
are the partners of the partnership.  The majority of our production  activities
are carried out through this partnership.

Compton Petroleum Finance  Corporation,  formed under the laws of Alberta,  is a
wholly-owned  subsidiary of Compton  Petroleum  Corporation.  Compton  Petroleum
Finance  Corporation  has no  independent  operations  and  has  no  significant
liabilities  or assets  other than US$450  million of 7-5/8% Senior  Notes,  its
equity interest in Hornet

                                      - 8 -
<PAGE>

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

                   [GRAPHIC OMITTED -- ORGANIZATIONAL CHART]

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


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


                       GENERAL DEVELOPMENT OF THE BUSINESS

Compton is an Alberta based  independent  public company actively engaged in the
exploration,  development, and production of natural gas, ngls, and crude oil in
the Western Canada  Sedimentary Basin (the "WCSB") in Canada.  Compton commenced
operations in 1993 with $1 million of share capital, a small dedicated technical
team, and a large seismic database. The objective was to build a company through
internal,  full  cycle  exploration,  complemented  by  strategic  acquisitions.
Compton's  goal was to create a company  capable of long term  sustained  growth
with a primary focus on natural gas.  Compton's focus and strategy have remained
unchanged  since  conception.  Compton's  shares are listed on the Toronto Stock
Exchange  under the  symbol  CMT and on the New York  Stock  Exchange  under the
symbol CMZ.

THREE YEAR HISTORY

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

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

In  2005,  progress  was  made on  each of the  Company's  four  resource  plays
including the plains Belly  River/Edmonton  group which  includes the Horeseshoe
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.  Compton was one of the top 10 most active operators in Canada
throughout the year. The Company's consolidated capital program of $513 million,
included  drilling  392 gross  (334 net)  wells  with a 96%  success  rate.  The
drilling program resulted in an exit production rate of 35,500 boe/d and average
production  of 29,424 boe/d for

                                      - 9 -
<PAGE>

the year.  High  commodity  prices and increased  production  generated  record
revenue of $558 million.  Compton's  proved plus probable  reserves totaled 207
MMBoe  as at  December  31,  2005.  Approximately  62  MMBoe  was  added to the
Company's   proved  plus  probable   reserves   through   drilling   successes,
acquisitions, and extensions.

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 ("FD&A") 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.


                           DESCRIPTION OF THE BUSINESS

EXPLORATION AND PRODUCTION OPERATIONS

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

BUSINESS PLAN AND OPERATING STRATEGY

The  Company's  business  plan  is  to  grow  Compton's  reserves  and  maximize
production  and cash flow from its core  geographic  areas and other areas where
Compton has technical  expertise.  Management is implementing  this objective by
focusing on the efficient  exploration,  development,  and  exploitation  of 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,
2006,  78%  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
ten years of drilling  inventory on existing lands.  Most of these planned wells
are expected to be in close proximity to producing wells in existing core areas.
Compton's  drilling  success  rate has

                                     - 10 -
<PAGE>

been at or above 90% for each of the past three years,  providing confidence in
the Company's  ability to  successfully  grow reserves and production  from its
extensive inventory of drilling locations.

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

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

PRINCIPAL PROPERTIES

Compton  engages in oil and gas  exploration  and  development  in the WCSB. Our
focus is on the Deep Basin  portion of the WCSB,  which  extends from  northwest
Alberta  and  British  Columbia  to the  United  States  border.  In this  large
geographical  region,  we pursue  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 stacked,  thrusted Foothills Upper Cretaceous Belly River play at
Callum  in the  south,  and the  Gething/Rock  Creek  sands at Niton in  central
Alberta.  Compton's  third  core  area,  located  in the Peace  River  Arch,  is
comprised of two oil properties at Worsley and Cecil.

Shallow Gas

The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow gas zones
cover more than 1,000  sections of Compton  held land in southern  Alberta.  The
entire 800 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 2006 we drilled  183 wells
through the Edmonton  Horseshoe  Canyon Group targeting the Belly River section,
for a total of 550 wells  drilled  as of year end.  This  allowed  for  numerous
recompletion and commingling opportunities. Going forward, we intend to focus on
downspacing,  development  drilling,  and  recompletions in order to establish a
resource  manufacturing  and processing  model designed to maximize  production.
Three key elements -- one industry  driven,  the others  Compton  driven -- have
recently come together to make this model possible.

    1.  In July 2006, the EUB announced a downspacing initiative for zones above
        the Mannville, including the Plains Belly River, that is intended to see
        standard  well  spacing  increase  from one to four  wells per  section.
        Reduced  spacing is critical in the  development  of our  unconventional
        reservoirs that require greater well density for more efficient resource
        development and  recognition.  With our current land holdings,  this new
        regulation  adds  over  4,000  locations  to  our  drilling   inventory.
        Additional  to  downspacing,   we  now  have  the  ability  to  maximize
        production through  commingling Belly River with the  Edmonton/Horseshoe
        Canyon zones.  The EUB released a directive for  commingling  on October
        31,  2006 that  allows  for  concurrent  production  of Belly  River and
        Edmonton/Horseshoe Canyon Coals as a single procedure, following minimal
        application.

    2.  We have a large 3D seismic data base,  totaling  2,140 km(2) (826 mi(2))
        as at December 31, 2006,  with an additional 427 km(2)(165  mi(2)) as of
        the first quarter of 2007.  The use of 3D seismic is key in  positioning
        downspace  well  locations  that maximize  production and reduce capital
        requirements.

                                     - 11 -
<PAGE>

    3.  In recent years, we have focused  efforts on establishing  and expanding
        infrastructure  and facilities in our core areas.  We currently have 466
        kilometres of low pressure pipelines. This system of compressors and low
        pressure  pipeline  gathering  systems  covers  a large  portion  of our
        existing land base.

2006  saw  Compton  take  advantage  of  new  EUB  downspacing  and  commingling
initiatives   to   successfully   test  our  seismic   modeling   and   complete
infrastructure  development.  In 2006, we drilled 25 sections to as many as four
wells per  section.  Preliminary  results on the second to fourth  wells in each
section have generally exceeded the first drill in the section.  As a result, we
intend  to ramp up our Belly  River/Edmonton  drilling  program  in 2007 to grow
production  from these zones.  Late in the fourth quarter of 2006, we tied in 21
Belly  River/Coalbed  Methane wells.  An additional 21 wells are projected to be
tied in during the first and second quarters of 2007.

In 2006 we expanded our southern  Alberta shallow gas compression  capability to
105 mmcf/d.

In 2007,  we have  budgeted to drill 215 shallow gas wells  targeting the Plains
Belly River/Edmonton group. In select areas, drilling is planned in groups of 20
to 40 wells to capitalize on downspacing  and associated cost  efficiencies.  As
well,  we have 69 hybrid  coal bed  methane  and sand gas  wells.  Low  pressure
gathering and compression  facilities are largely in place in the area to assist
in  reducing  on-stream  times.  It is our  intent  that  production  from these
multi-zone  wells will be  commingled  for  optimal  production  results.  Going
forward,  in 2008 and beyond,  we plan to  accelerate  production  by drilling a
large number of wells and tie-ins to existing facilities.  A 4,000 well drilling
inventory makes this possible.

Deep Gas

Compton has three deep gas plays: the Basal Quartz sands at Hooker, the stacked,
thrusted,  Belly River play at Callum in southern Alberta,  and the Gething/Rock
Creek sands at Niton in central 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.  This
play covers an  extensive  area of  approximately  124,800  net acres,  with our
working interest  averaging 85%. Current production extends over five townships,
and in 2006,  we drilled 18 wells at Hooker,  testing  the aerial  extent of the
play.  It  remains  apparent  that the edges of the  Hooker  pool have yet to be
defined.

In 2006, the total Hooker infrastructure system was expanded to 65 mmcf/d.

We believe that the key to maximizing  production  at Hooker,  or any Deep Basin
play,  is  downspacing  of  drilling  two wells per  section  to four  wells per
section.  Currently,  Compton's  drilling  program is approved for two wells per
section,  although  the  majority of the 120 gas wells  drilled to date by us in
this area are on single section spacing.  Our engineering and geological  models
indicate  that a  minimum  four  wells  per  section  is  required  for  optimal
production  in this area.  As such,  we have made an  application  to the EUB to
downspace on a pilot basis, with two other sections pending.  We intend to drill
approximately 20 Basal Quartz wells during 2007. The majority of these wells are
infill  locations  planned  for the second  half of 2007,  once  downspacing  is
approved.

CALLUM

Our  Callum  property  consists  of a  series  of  overpressured,  thrusted  low
permeability  Belly River sands in the foothills of southern  Alberta.  With the
acquisition  of our  partner's  interest in 2006, we now hold a 100% interest in
70,400  acres of land in this area.  A total of 13  exploratory  wells have been
drilled  over the life of the play by  Compton.  Based on our  initial  detailed
geological,  geophysical, and engineering analysis of seismic, cores, well logs,
test and production  data,  Callum appears to exhibit many  similarities  to the
deep unconventional gas pools of the Rocky Mountain region of the United States.

                                     - 12 -
<PAGE>

In 2006, we drilled five exploratory  wells, all of which  encountered  multiple
sands.  The wells were cased and extensively  cored.  The two most recent wells,
drilled  during the third quarter of 2006, are two and 15 miles south of current
production,  respectively,  and following  laboratory  analysis of the cores, we
intend to complete these wells.

Compton is conducting  environmental  studies on four  additional  pads prior to
submitting  the  required  license   applications.   We  are  working  with  all
stakeholders in the area to proceed in an environmentally responsible manner and
we remain  committed to minimizing  the impact of our  activities.  To this end,
drilling in this area is based on one drill pad per section.

In 2007, we plan to drill two exploratory  wells at Callum.  We remain confident
in pursuing this challenging and technically complex play. We intend to increase
our drilling  activities in the area once regulatory  well licensing  issues are
resolved.

NITON

The Niton area in central Alberta, 150 miles west of Edmonton, is in the Alberta
Deep Basin. Our main targets are the Jurassic Rock Creek and Cretaceous Gething,
analogous  to the Hooker  pool in  southern  Alberta.  Proprietary  exploration,
development, and operations knowledge gained in southern Alberta has resulted in
accelerated  growth of this core area. We have  assembled  our 156,800  (128,000
net) acres of land in this  multi-target  area.  In 2006,  31 wells were drilled
with results exceeding our expectations.

Compton  undertook a major facility  project at Niton during 2006. At our McLeod
River  7-34-54-14W5  gas plant,  all major  equipment  was  purchased in 2006 to
complete a gas plant expansion from 18 to 23 mmscf/d processing capacity,  which
we expect to be completed by March 31, 2007.

Drilling results at Niton continue to exceed our expectations.  In 2007, we plan
to drill 39 wells in this area.

WORSLEY/CECIL

Located in the Peace River Arch, the Worsley and Cecil  properties  produce from
the Triassic  Charlie  Lake  Formation,  a layered  sandy  Carbonate.  These two
properties comprise the majority of Compton's conventional oil production.

For 2006,  the Worsley pool was the focus of the  Company's  operations  in this
area. We drilled 27 Charlie Lake oil wells in 2006,  for a total of 118 vertical
and 12 horizontal wells in the area.

The horizontal  drilling program at Worsley has produced very positive  results.
One  horizontal  well replaces three  vertical  wells,  at a cost saving of $1.2
million.  Horizontal  wells allow  successful  drilling  and  production  in oil
bearing rock layers where underlying  water is recognized.  In 2005, the Company
initiated a waterflood  program in this area which we project will  increase the
ultimate  recovery factor for the pool to 25% from 15% on primary  depletion.  A
total of eight wells have been converted to water injectors.

The Worsley gas plant was  successfully  expanded with the  installation of a 15
mmcf/d  amine  unit in the first  quarter of 2007.  The plant is now  capable of
processing 13 mmcf/d.

In 2007,  we intend  to focus on  horizontal  drilling  and  definition  of pool
boundaries in this area.


PRINCIPAL MARKETS AND DISTRIBUTION METHODS

Compton's  natural gas  production  is sold under a  combination  of longer term
contracts  with  aggregators  and  short  term  daily  or 30  day  AECO  indexed
contracts. Approximately 11% of the Company's natural gas production in 2006 was
committed  to  aggregators,  compared to an average of 10% in 2005.  The average
aggregator  price  realized in 2006 was $1.31/Mcf  less than the  non-aggregator
prices realized during the year.  Natural gas production is transported  through
regulated pipelines within Alberta, at tolls requiring government approval.

The Company's crude oil sales are priced at Edmonton  postings and are typically
sold on 30 day  evergreen  arrangements.  Natural  gas liquids are bid out on an
annual basis to obtain the most favorable  pricing.  The


                                     - 13 -
<PAGE>


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, Alberta Energy and Utilities Board,
Alberta  Environmental   Protection,   and  other  related  associations,   thus
demonstrating  Compton's  commitment to minimizing  the Company's  environmental
impact.

The  Company  carries  out  its  activities  in  compliance  with  all  relevant
regulations and industry best practices.  At present,  the Company believes that
it meets all existing  environmental  standards and regulations and has included
appropriate  amounts  in its  capital  expenditure  budget to  continue  to meet
current environmental protection  requirements.  The Company does not anticipate
making extraordinary  material expenditures for environmental  compliance during
2007.  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,  2006,  Compton had 168  full-time  employees in its Calgary
office and 57 full-time employees at field locations.

COMPETITIVE CONDITIONS

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


                                  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.


                                      - 14 -
<PAGE>


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

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

Compton's strategies to minimize this inherent risk include focusing on selected
core  areas  in  Western  Canada  with  high  working   interests  and  assuming
operatorship of key facilities.  The Company utilizes a team of highly qualified
professionals  with  expertise and experience in these areas.  Compton  assesses
strategic  acquisitions to complement  existing  activities while striving for a
balance  between   exploration  and  lower  risk  development  and  exploitation
prospects.

UNCERTAINTY OF RESERVE ESTIMATES

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


                                      - 15 -
<PAGE>

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.

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


                                      - 16 -
<PAGE>

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.

RELIANCE ON KEY EMPLOYEES

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

ENVIRONMENTAL RISKS

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

Furthermore,  future changes in environmental  laws and  regulations,  including
adoption of stricter  standards or more stringent  enforcement,  could result in
curtailment of production or materially increased costs, such as fines, incurred
liability,  and increased capital expenditures and operating costs, any of which
could have a material  adverse effect on our financial  condition.  For example,
Canada is a signatory  to the United  Nations  Framework  Convention  on Climate
Change and has ratified the Kyoto Protocol established thereunder to set legally
binding  targets to reduce  nationwide  emissions  of carbon  dioxide,  methane,
nitrous oxide,  and other so-called  "greenhouse  gases."  Compton's  production
facilities and other  operations and activities emit  greenhouse  gases that may
subject the Company to legislation regulating emissions of greenhouse gases. The
Government of Canada has released the first reading of Canada's Clean Air 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,  together
with  provincial  emission  reduction  requirements,  such as those  proposed in
Alberta's  CLIMATE  CHANGE  AND  EMISSIONS  MANAGEMENT  ACT  (which  has been in
existence  since  2003,  but  none  of  the  sections  that  prescribe  targets,
timeframes,  and compliance  options with respect to the reduction of greenhouse
gases have been proclaimed  into force),  may require the reduction of emissions
or emissions intensity of the Company's operations and facilities.

Compliance with such  legislation  can require  significant  expenditures  and a
failure  to comply  may  result in the  issuance  of  "clean  up"  orders or the
imposition of fines and penalties, some of which may be material. It is possible
that the costs of complying  with  environmental  regulations in the future will
have a material adverse effect on the


                                      - 17 -
<PAGE>

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  94% of the  Company's  oil  and  natural  gas  reserves,  have  been
evaluated in a report (the "MAJOR REPORT") as of December 31, 2006,  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 6% of
the Company's oil and natural gas reserves have been  evaluated in a report (the
"MINOR  REPORT") as of December 31,  2006,  prepared  internally  by Compton and
audited by Netherland Sewell. The following summary of the Company's reserves is
calculated  and  reported  in  accordance  with  National   Instrument   51-101,
"Standards  of  Disclosure  for  Oil  and  Gas   Activities".   Assumptions  and
qualifications  relating  to costs,  prices  for  future  production,  and other
matters are included  below.  The 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 Netherland  Sewell Report will be attained and variances  could be material.
Other  assumptions  and  qualifications  relating to costs and other matters are
summarized  in the notes to the  following  tables.  The  recovery  and reserves
estimates on Compton's  properties  described  herein are  estimates  only.  The
actual  reserves  on  Compton's  properties  may be  greater  or less than those
calculated  and  these  variances  may be  material.  Compton  has no heavy  oil
reserves and "crude oil" refers to light and medium crude oil only.

In December  2006,  Compton  entered into  agreements for the sale of two minor,
non-core  properties  that  generated net proceeds of $45.9 million all of which
were received in the first quarter of 2007.  The effective  dates of these sales
were  December 31, 2006 after which time  Compton was no longer  entitled to the
sales  proceeds  from  production  volumes.   Accordingly,   we  excluded  these
properties  from the December  31, 2006 reserve  report the details of which and
related disclosures are fully set out in the following sections of this AIF. The
effect of these sales on corporate  indebtedness  as at December 31, 2006 is set
out in the Liquidity and Capital  Resource  section of Management's  Discuss and
Analysis in the Company's 2006 Annual Report.

This  statement is dated March 7, 2007. The  information  being provided in this
statement has an effective  date of December 31, 2006 and a preparation  date of
March 7, 2007.

CONSTANT PRICES AND COSTS

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


                                      - 18 -
<PAGE>

SUMMARY OF OIL AND GAS RESERVES USING CONSTANT PRICING AS OF DECEMBER 31, 2006

<TABLE>
<CAPTION>
==================================================================================================================
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             15,178    14,097    434,615     354,571     7,904     5,634     1,311      1,165
Developed non-producing
                                 1,725     1,603     68,358      56,504     1,154       795        50         39
Undeveloped                      3,227     2,760    170,242     142,256     1,996     1,456        86         72
------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                    20,130    18,459    673,215     553,331    11,054     7,885     1,447      1,276
==================================================================================================================
</TABLE>

(1)  Numbers may not add due to rounding.
(2)  The solution and associated gas represents 4% of the Company's  natural gas
     reserves and is therefore considered immaterial and is not broken out.

The table set forth below  summarizes  the future net revenue as of December 31,
2006, based on constant price and cost assumptions.

SUMMARY OF FUTURE NET REVENUE AS OF DECEMBER 31, 2006 (CONSTANT PRICES)

<TABLE>
<CAPTION>
================================================================================================================
RESERVES CATEGORY(1)                                                FUTURE NET REVENUE ($000S)

                                                BEFORE INCOME TAXES DISCOUNTED  AFTER INCOME TAXES DISCOUNTED AT
                                                         AT (%/YEAR)                       (%/YEAR)
                                                     0%              10%             0%              10%
----------------------------------------------------------------------------------------------------------------
<S>                                                <C>              <C>             <C>             <C>
PROVED
Developed producing                                $1,883,506       $1,023,093      $1,596,510         $921,901
Developed non-producing                               398,462          191,794         328,364          167,477
Undeveloped                                           684,893          229,608         522,188          171,741
----------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                       $2,966,860       $1,444,494      $2,447,062       $1,261,120
================================================================================================================
</TABLE>

(1)  Numbers may not add due to rounding.

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

TOTAL  FUTURE NET  REVENUE  (UNDISCOUNTED)  AS OF DECEMBER  31,  2006  (CONSTANT
PRICES)

<TABLE>
<CAPTION>
=======================================================================================================================
  RESERVES   REVENUE      ROYALTIES   OPERATING  DEVELOPMENT       WELL         FUTURE NET   INCOME TAXES  FUTURE NET
  CATEGORY   ($000S)       ($000S)      COSTS       COSTS      ABANDONMENT    REVENUE BEFORE   ($000S)    REVENUE AFTER
                                       ($000S)     ($000S)    COSTS ($000S)    INCOME TAXES               INCOME TAXES
                                                                                 ($000S)                     ($000S)
-----------------------------------------------------------------------------------------------------------------------
<S>          <C>         <C>         <C>          <C>           <C>            <C>            <C>         <C>
Proved       $6,375,523  $1,122,494  $1,946,470   $310,568      $29,131        $2,966,860     $519,798    $2,447,062
=======================================================================================================================
</TABLE>

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


                                      - 19 -
<PAGE>

TOTAL FUTURE NET REVENUE BY  PRODUCTION  TYPE AS OF DECEMBER 31, 2006  (CONSTANT
PRICES)

<TABLE>
<CAPTION>
====================================================================================================================
  RESERVES CATEGORY                 PRODUCTION TYPE                  FUTURE NET REVENUE BEFORE INCOME TAXES
                                                                        (DISCOUNTED AT 10%/YEAR) ($000S)
--------------------------------------------------------------------------------------------------------------------
<S>                       <C>                                                        <C>
Proved                    Crude oil (1)                                              $  390,794
                          Natural gas, ngls, and sulphur (2)                         $1,053,701
====================================================================================================================
</TABLE>
(1)  Includes solution gas and related ngls.
(2)  Excludes solution gas and related ngls.

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.

SUMMARY OF OIL AND GAS RESERVES USING FORECAST PRICING AS OF DECEMBER 31, 2006

<TABLE>
<CAPTION>
=====================================================================================================================
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               15,065     13,985     443,154    362,075     8,021     5,734     1,392       1,237
Developed non-producing            1,714      1,592      68,685     56,795     1,152       795        50          40
Undeveloped                        3,220      2,752     174,999    146,232     2,016     1,473       115          96
---------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                      19,999     18,329     686,838    565,102    11,189     8,002     1,557       1,373
PROBABLE                           9,234      7,884     502,260    418,568     7,879     5,759       714         603
---------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE        29,233     26,213   1,189,099    983,671    19,068    13,761     2,271       1,975
=====================================================================================================================
</TABLE>
(1)  Numbers may not add due to rounding.
(2)  The solution and associated gas represents 3% of the Company's  natural gas
     reserves and is therefore considered immaterial and is not broken out.

The tables set forth below  summarize  the future net revenue as of December 31,
2006, based on forecast prices and cost assumptions.

SUMMARY OF FUTURE NET REVENUE AS OF DECEMBER 31, 2006 (FORECAST PRICES)

<TABLE>
<CAPTION>

====================================================================================================================
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                 $2,773,936    $1,748,886    $1,446,076   $1,302,527    $1,057,169    $  901,024
Developed non-producing                546,346       339,853       273,957      242,086       187,093       152,203
Undeveloped                          1,072,420       593,417       437,949      362,601       233,399       153,300
--------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                        $4,392,702    $2,682,156    $2,157,982   $1,907,214    $1,477,661    $1,206,527
PROBABLE                             3,239,955     1,623,302     1,153,903      937,863       586,886       383,808
--------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE          $7,632,658    $4,305,457    $3,311,885   $2,845,077    $2,064,547    $1,590,335
====================================================================================================================
</TABLE>
(1)  Numbers may not add due to rounding.


                                      - 20 -
<PAGE>

<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                $2,224,955    $1,447,137    $1,220,454     $1,112,098    $  923,647    $  800,161
Developed non-producing               429,793       274,512       224,719        200,383       157,742       130,056
Undeveloped                           801,524       443,334       326,428        269,255       170,022       107,434
---------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                       $3,456,273    $2,164,983    $1,771,601     $1,581,736    $1,251,410    $1,037,651
PROBABLE                            2,300,896     1,117,665       781,978        627,737       376,436       230,110
---------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE         $5,757,170    $3,282,647    $2,553,579     $2,209,473    $1,627,846    $1,267,760
=====================================================================================================================
</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.

TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2006
(FORECAST PRICES)

<TABLE>
<CAPTION>
======================================================================================================================
   RESERVES      REVENUE    ROYALTIES   OPERATING   DEVELOPMENT     WELL         FUTURE NET  INCOME       FUTURE NET
   CATEGORY      ($000S)     ($000S)      COSTS       COSTS      ABANDONMENT    REVENUE BEFORE TAXES     REVENUE AFTER
                                         ($000S)     ($000S)      COSTS(1)      INCOME TAXES  ($000S)    INCOME TAXES
                                                                   ($000S)        ($000S)                   ($000S)
----------------------------------------------------------------------------------------------------------------------
<S>            <C>          <C>         <C>          <C>              <C>         <C>         <C>          <C>
Proved         $ 9,021,222  $1,581,569  $2,672,569   $  329,690       $44,692     $4,392,702  $  936,429   $3,456,273
Proved plus
probable       $15,179,800  $2,668,280  $3,741,687   $1,067,464       $69,711     $7,632,658  $1,875,488   $5,757,170
======================================================================================================================
</TABLE>
(1)  Includes, at minimum, well abandonment costs (rather than total abandonment
     and reclamation costs).

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

TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2006
(FORECAST PRICES)

<TABLE>
<CAPTION>
====================================================================================================================
RESERVES CATEGORY                    PRODUCTION TYPE            FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED
                                                                               AT 10%/YEAR) ($000S)
--------------------------------------------------------------------------------------------------------------------
<S>                         <C>                                                       <C>
Proved                      Crude oil (1)                                             $  425,859
                            Natural gas and ngls (2)                                  $1,481,355

Proved plus probable        Crude oil (1)                                             $  585,546
                            Natural gas and ngls (2)                                  $2,259,531
====================================================================================================================
</TABLE>
(1)  Includes solution gas and related ngls.
(2)  Excludes solution gas and related ngls.


                                      - 21 -
<PAGE>

                               PRICING ASSUMPTIONS

CONSTANT PRICES USED IN ESTIMATES

Constant price assumptions presume the continuance of current laws, regulations,
and  operating  costs in effect on the date of the  Report.  Future net  revenue
calculated  using constant prices and costs is based upon the price  assumptions
set out below.  The prices are founded upon the  assumptions  made by Netherland
Sewell as of December 31, 2006.

SUMMARY OF CONSTANT PRICING ASSUMPTIONS AS OF DECEMBER 31, 2006

<TABLE>
<CAPTION>
=====================================================================================================================
     YEAR                  CRUDE OIL              NATURAL GAS                NGLS                SULPHUR    EXCHANGE
                                                                                                              RATE
                                                                                                            $CDN/$US
                   WTI CUSHING     EDMONTON PAR    AECO-C SPOT    PROPANE    BUTANE   PENTANES+  PLANT GATE
                OKLAHOMA$ US/BBL    40(0) API      ($CDN/MMBTU) ($CDN/BBL) ($CDN/BBL) ($CDN/BBL) ($CDN/LT)
                                    ($CDN/BBL)
---------------------------------------------------------------------------------------------------------------------
<S>                 <C>              <C>             <C>         <C>        <C>        <C>        <C>        <C>
Dec. 31, 2006       $57.75           $69.60          $6.13       $42.12     $54.05     $71.99     $7.41      $0.85
=====================================================================================================================
</TABLE>

FORECAST PRICES USED IN ESTIMATES

Future net revenue  calculated using forecast prices and costs is based upon the
price assumptions set out below.  Netherland Sewell incorporated price forecasts
which were the average of the December 31, 2006  pricing  forecasts  prepared by
four major Canadian consulting firms in estimating Compton's reserves data using
forecast pricing and costs.

SUMMARY OF FORECAST  PRICING AND INFLATION  RATE  ASSUMPTIONS AS OF DECEMBER 31,
2006

<TABLE>
<CAPTION>
======================================================================================================================
   YEAR              CRUDE OIL           NATURAL GAS               NGLS                SULPHUR    INFLATION   EXCHANGE
                                                                                                   RATE (1)     RATE
                                                                                                    %/YEAR    $CDN/$US
             WTI CUSHING  EDMONTON PAR   AECO C SPOT   PROPANE    BUTANE    PENTANES+  PLANT GATE
              OKLAHOMA      40(0) API   ($CDN/MMBTU)  ($CDN/BBL)($CDN/BBL) ($CDN/BBL)  ($CDN/LT)
               $US/BBL     ($CDN/BBL)
-----------------------------------------------------------------------------------------------------------------------
<S>           <C>           <C>            <C>           <C>      <C>        <C>        <C>          <C>      <C>
Forecast
2007          $63.81        $72.00         $7.39         $44.17   $55.42     $74.11     $21.50        2.0%    $0.85
2008          $64.84        $73.17         $7.87         $45.12   $55.28     $75.30     $16.13        2.0%    $0.85
2009          $62.74        $70.76         $7.80         $43.95   $53.55     $72.89     $14.44        2.0%    $0.85
2010          $60.69        $68.36         $7.81         $42.65   $51.72     $70.44     $12.91        2.0%    $0.85
2011          $59.03        $66.44         $7.98         $41.68   $50.25     $68.46     $13.48        2.0%    $0.85
2012          $59.52        $66.98         $8.18         $42.04   $50.62     $69.02     $14.06        2.0%    $0.85
2013          $60.65        $68.27         $8.33         $42.89   $51.60     $70.34     $14.64        2.0%    $0.85
2014          $61.88        $69.70         $8.52         $43.72   $52.73     $71.80     $15.22        2.0%    $0.85
2015          $63.14        $71.06         $8.69         $44.64   $53.70     $73.28     $15.81        2.0%    $0.85
2016          $64.40        $72.51         $8.87         $45.50   $54.83     $74.75     $16.42        2.0%    $0.85
2017          $65.70        $73.92         $9.03         $46.44   $55.87     $76.19     $17.03        2.0%    $0.85
Thereafter      2.0%          2.0%          2.0%           2.0%     2.0%       2.0%       2.0%        2.0%    $0.85
======================================================================================================================
</TABLE>
(1)  Inflation rate for operating and capital costs.

The  weighted  average  realized  sales  price for  Compton  for the year  ended
December  31, 2006 was  $6.37/Mcf  for natural  gas,  $63.28/bbl  for crude oil,
$51.40/bbl for ngls, and $0.47/lt for sulphur.


                                      - 22 -
<PAGE>

          RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE

RESERVES RECONCILIATION

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

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

<TABLE>
<CAPTION>
===================================================================================================================
                                            CRUDE OIL                                           NGLS
                                                                             NET
                            NET PROVED  NET PROBABLE  NET PROVED PLUS      PROVED    NET PROBABLE   NET PROVED PLUS
                              (MBBL)       (MBBL)     PROBABLE (MBBL)      (MBBL)       (MBBL)      PROBABLE (MBBL)
-------------------------------------------------------------------------------------------------------------------
<S>                              <C>          <C>           <C>              <C>           <C>             <C>
December 31, 2005                19,725       5,762         25,488           7,441         4,629           12,070
Extensions                          392         561            953             524           472              996
Improved recovery                   789         725          1,514             238           344              582
Technical revisions                (566)        800            234              (1)         (127)           (128)
Discoveries                          31           -             31             286            54              340
Acquisitions                          8          36             44             214           401              615
Dispositions(2)                     (67)          -            (67)           (162)          (14)            (176)
Production                       (1,983)          -         (1,983)           (537)            -             (537)
-------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006                18,329       7,884         26,213           8,002         5,759           13,761
===================================================================================================================

<CAPTION>
===================================================================================================================
                                           NATURAL GAS                                    SULPHUR

                                                        NET PROVED                                    NET PROVED
                            NET PROVED  NET PROBABLE   PLUS PROBABLE    NET PROVED   NET PROBABLE    PLUS PROBABLE
                              (MMCF)       (MMCF)         (MMCF)           (MLT)        (MLT)             (MLT)
-------------------------------------------------------------------------------------------------------------------
<S>                             <C>          <C>           <C>               <C>           <C>              <C>
December 31, 2005               449,790      337,719       787,509           1,565         656              2,221
Extensions                       27,309       20,086        47,395               -           -                  -
Improved recovery                50,394      125,247       175,641               -           -                  -
Technical revisions              75,206      (84,481)       (9,275)           (100)        (53)              (153)
Discoveries                       4,312        4,441         8,753               -           -                  -
Acquisitions                     11,331       16,982        28,313               -           -                  -
Dispositions(2)                 (12,939)      (1,426)      (14,365)              -           -                  -
Production                      (40,300)           -       (40,300)            (93)          -                (93)
-------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006               565,102      418,568       983,671           1,373         603              1,975
===================================================================================================================
</TABLE>
(1)  Prepared by Management. Numbers may not add due to rounding.
(2)  Includes  dispositions of non-core  properties  which closed  subsequent to
     December 31, 2006.


                                      - 23 -
<PAGE>

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

<TABLE>
<CAPTION>
===================================================================================================================
                                                                                       TOTAL RESERVES

                                                                                          NET         NET PROVED
                                                                         NET PROVED    PROBABLE      PLUS PROBABLE
                                                                           (MBOE)       (MBOE)           (MBOE)
-------------------------------------------------------------------------------------------------------------------
<S>                                                                       <C>              <C>           <C>
December 31, 2005                                                         103,696          67,334        171,031
Extensions                                                                  5,468           4,381          9,848
Improved recovery                                                           9,426          21,944         31,370
Technical revisions                                                        11,867         (13,460)        (1,593)
Discoveries                                                                 1,036             794          1,830
Acquisitions                                                                2,111           3,267          5,378
Dispositions(2)                                                            (2,386)           (252)        (2,637)
Production                                                                 (9,330)              -         (9,330)
-------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 2006                                                         121,888          84,007        205,895
===================================================================================================================
</TABLE>
(1)  Prepared by Management. Numbers may not add due to rounding.
(2)  Includes  dispositions of non-core  properties  which closed  subsequent to
     December 31, 2006.

FUTURE NET REVENUE RECONCILIATION

The following table reconciles  changes between the future net revenue estimates
at December 31, 2006 and the  corresponding  estimates in the prior year,  using
constant prices and costs, discounted at 10%.

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

<TABLE>
<CAPTION>
===================================================================================================================
                                                                                                           2006
                                                                                                         ($000s)(2)
-------------------------------------------------------------------------------------------------------------------
<S>                                                                                                     <C>
Estimated future net revenue at beginning of year                                                       $2,151,700
Sales and transfers of oil and gas produced, net of production costs and royalties                        (291,896)
Net change in sales, prices, production costs and royalties related to future production                  (731,330)
Changes in previously estimated development costs incurred during the period                              (207,421)
Changes in estimated future development costs                                                             (221,882)
Net change from extensions and improved recovery                                                           170,776
Net change from discoveries                                                                                 13,019
Acquisitions of reserves                                                                                   (23,176)
Dispositions of reserves (3)                                                                                47,220
Net change resulting from revisions in quantity estimates                                                  (74,504)
Accretion of discount                                                                                      215,170
Net change in income taxes (4)                                                                             396,818
-------------------------------------------------------------------------------------------------------------------
Estimated future net revenue at end of year                                                             $1,444,494
===================================================================================================================
</TABLE>
(1)  Prepared by Management.
(2)  Except for "Net Change in Income Taxes," the amounts above are before tax.
(3)  Includes  dispositions of non-core  properties  which closed  subsequent to
     December 31, 2006.
(4)  Includes  both  income  taxes  incurred  during the  period and  changes in
     estimated future income tax expenses.


                                     - 24 -
<PAGE>


                ADDITIONAL INFORMATION RELATING TO RESERVES DATA

UNDEVELOPED RESERVES

The  following  discussion  generally  describes  the  basis  on  which  Compton
attributes proved and probable undeveloped reserves and its plans for developing
those undeveloped reserves.

PROVED UNDEVELOPED RESERVES

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

The following table  summarizes the Company's proved  undeveloped  reserves over
the past five 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>                      <C>
          2006                      3,220                 174,999                2,016                    115
          2005                      5,019                  84,333                1,731                    118
          2004                      2,815                  51,828                1,310                    121
          2003                      2,494                  49,324                  873                    124
          2002                        778                  26,638                  577                      2
===============================================================================================================
</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 2008.

The following table summarizes the Company's probable  undeveloped reserves over
the past five 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>                      <C>
          2006                      5,533                 420,522                6,446                    526
          2005                      5,779                 355,237                5,646                    772
          2004                      7,908                 199,785                4,716                    888
          2003                      2,847                 165,298                2,158                    793
        2002(1)                     6,539                 190,844                3,779                  1,973
================================================================================================================
</TABLE>
(1)      the probable values for this year contain developed reserves.

                                     - 25 -
<PAGE>


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 following reserves
categories:

DEVELOPMENT COSTS DEDUCTED IN ESTIMATING FUTURE NET REVENUES(1)

<TABLE>
<CAPTION>
=====================================================================================================================
YEAR                                                        PROVED                           PROVED PLUS PROBABLE
                                        CONSTANT PRICES AND        FORECAST PRICES AND        FORECAST PRICES AND
                                         COSTS/YEAR ($000S)        COSTS/YEAR ($000S)         COSTS/YEAR ($000S)
---------------------------------------------------------------------------------------------------------------------
Undiscounted
<S>                                             <C>                     <C>                          <C>
   2007                                         $158,243                $168,576                     $ 273,483
   2008                                          110,233                 113,497                       323,802
   2009                                           35,840                  40,264                       237,715
   2010                                           11,148                  12,089                       200,238
   2011                                              400                     504                        18,207
   Remaining                                      23,835                  39,452                        83,730
---------------------------------------------------------------------------------------------------------------------
Total undiscounted                              $339,699                $374,382                    $1,137,175

Total discounted at 10% per year                $286,694                $304,131                     $ 901,048
=====================================================================================================================

</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.

                                     - 26 -
<PAGE>

                          OTHER OIL AND GAS INFORMATION

OIL AND GAS PROPERTIES AND WELLS

The following  table  summarizes  the location of the Company's  interests as at
December  31,  2006,  in crude oil and natural gas wells which are  producing or
which the Company considers to be capable of production.

<TABLE>
<CAPTION>
=====================================================================================================================
AREA                      PRODUCING CRUDE     SHUT-IN CRUDE       PRODUCING      SHUT-IN NATURAL      TOTAL WELLS
                             OIL WELLS          OIL WELLS        NATURAL GAS        GAS WELLS
                                                                    WELLS
                           GROSS     NET     GROSS      NET     GROSS     NET     GROSS     NET     GROSS     NET
---------------------------------------------------------------------------------------------------------------------
ALBERTA
<S>                            <C>      <C>       <C>      <C>      <C>     <C>      <C>      <C>    <C>         <C>
  South                        91       37        31       13       932     724      239      205    1,293       979
  Central                     177       88        30        8       508     209      137       49      852       354
  Peace River Arch            372      235        58        7       109      45       49       19      588       306
BC                              6        -         1        -        43       3        7        1       57         4
---------------------------------------------------------------------------------------------------------------------
TOTAL WELLS                   646      360       120       28     1,592     981      432      274    2,790     1,643
=====================================================================================================================
</TABLE>


The number of shut in oil and gas wells  capable of  production  at December 31,
2006  increased  from 2005  because  well  tie-ins were delayed as the result of
abnormally wet weather during the summer months of 2006.

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, 2006.

<TABLE>
<CAPTION>
=====================================================================================================================
AREA                                                                                GROSS ACRES        NET ACRES
---------------------------------------------------------------------------------------------------------------------
<S>                                                                                     <C>                <C>
British Columbia                                                                        28,845             4,595
Alberta                                                                                924,745           767,408
Saskatchewan                                                                            23,157            23,157
Manitoba                                                                                 3,432             3,032
---------------------------------------------------------------------------------------------------------------------
TOTAL                                                                                  980,179           798,192
=====================================================================================================================
</TABLE>


Approximately  40,127 net acres of undeveloped land could expire by December 31,
2007.  However,  the Company's 2007 exploration and development  activities will
defer the expiry of a portion of these lands.

FORWARD CONTRACTS

In 2006,  Compton's  realized  average field price was $44.05/boe,  comprised of
$6.37/Mcf for natural gas and $58.53/bbl for liquids. In 2005, the average field
prices of natural gas and liquids were $8.42/Mcf and  $56.04/bbl,  respectively,
for an average price of $51.95/boe.

Compton's  natural gas  production  is sold under a  combination  of longer term
contracts  with  aggregators  and  short  term  daily  or 30  day  AECO  indexed
contracts. Approximately 11% of the Company's natural gas production in 2006 was
committed to aggregators.  The average  aggregator  price realized was $1.31/Mcf
less than the non-aggregator prices realized during the year.

                                     - 27 -
<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  1,600 net well sites and  facilities is the sum of the
calculated  abandonment  and  reclamation  liabilities  adjusted for  designated
status as active,  inactive,  abandoned,  or problem site. Information regarding
environmental  remediation  costs and other  liability  issues for site specific
concerns were derived from a review of historical  audit and assessment  reports
of sites and facilities. An inflation rate of 2% and a credit adjusted risk free
rate of 10.6% was used in the fair value calculation.

Total asset retirement  costs, net of estimated  salvage values, is $113 million
or $9 million when  discounted  at 10%. The  undiscounted  ARO  associated  with
pipelines and facilities is $50 million and is not deducted in estimating  total
future net revenue,  as calculated in the Company's reserve report.  The Company
expects to pay $4 million dollars in ARO costs between 2007 and 2010.

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 2006,  Compton incurred $72 million of exploration  costs and $416 million of
development  costs.  Additionally,  $33  million  was spent on  proved  property
acquisitions and $2 million was spent on unproved property acquisitions.

EXPLORATION AND DEVELOPMENT ACTIVITIES

The  following  table sets forth the number of crude oil 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,
2006 and 2005.  Fifteen  wells drilled in 2006,  which are standing  cased wells
awaiting completion and testing, are not included in the following table.

                                     - 28 -
<PAGE>

<TABLE>
<CAPTION>
======================================================================================================================
                                          YEAR ENDED DECEMBER 31, 2006             YEAR ENDED DECEMBER 31, 2005(1)
                                         DEVELOPMENT         EXPLORATORY           DEVELOPMENT        EXPLORATORY
                                        GROSS      NET     GROSS      NET        GROSS      NET     GROSS      NET
---------------------------------------------------------------------------------------------------------------------
<S>                                      <C>       <C>        <C>      <C>        <C>       <C>        <C>      <C>
Natural gas                              222       180        29       24         200       158        60       56
Crude oil                                 50        34         6        5         105        96        10        9
Dry and abandoned                         17        14         3        3           9         8         8        7
---------------------------------------------------------------------------------------------------------------------
TOTAL                                    289       228        38       32         314       262        78       72
SUCCESS RATIO                                          94%                                      96%
======================================================================================================================
</TABLE>
(1)  2005 revised to include four wells previously  classified as standing cased
     wells.

In 2007,  the Company will continue to focus its  resources in Alberta,  Canada.
Compton's overall objective for 2007 is the recognition of its unbooked resource
potential. The Company has developed a $375 million capital expenditure plan for
2007, encompassing up to 330 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.

GROSS NATURAL GAS AND LIQUIDS PRODUCTION

<TABLE>
<CAPTION>
=====================================================================================================================
PRODUCT TYPE                                           FISCAL 2006 THREE MONTHS ENDED
                                                                                                        YEAR ENDED
                                           MARCH 31,    JUNE 30,    SEPTEMBER 30,     DECEMBER 31,     DECEMBER 31,
                                             2006         2006          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.


                                     - 29 -
<PAGE>

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

Natural gas liquids (boe/d)(1)                 2,591       2,579         2,411              2,605          2,546
Natural gas liquids (Mboe)(1)                    233         235           222                240            930

Crude oil (bbl/d)                              4,499       4,668         4,940              6,274          5,100
Crude oil (Mbbls)                                405         425           454                577          1,861

Total liquids (boe/d)                          7,090       7,249         7,351              8,879          7,646
Total liquids (Mboe)                             638         660           676                817          2,791

Total (boe/d)                                 28,714      28,877        29,041             31,042         29,424
Total (Mboe)                                   2,584       2,628         2,672              2,856         10,740
======================================================================================================================
</TABLE>
(1)  Includes sulphur.


2007 PRODUCTION ESTIMATES

Production  volumes  in  2007,  as  estimated  in the  reserve  forecast  before
deduction of royalties,  are set forth below. Production volumes are the same in
both the constant price case and the forecast price case.

<TABLE>
<CAPTION>
=====================================================================================================================
RESERVES CATEGORY(1)                     CRUDE OIL     NATURAL GAS        NGLS        SULPHUR             TOTAL
                                          (BBL/D)        (MMCF/D)       (BBL/D)        (LT/D)             (BOE/D)
---------------------------------------------------------------------------------------------------------------------
PROVED
<S>                                         <C>               <C>          <C>            <C>             <C>
Developed producing                         5,031             109          1,872          167             25,241
Developed non-producing                       539              14            252            2              3,148
Undeveloped                                   406              15            281            -              3,236
---------------------------------------------------------------------------------------------------------------------
TOTAL PROVED                                5,976             138          2,404          169             31,626
PROBABLE                                      908              15            259            7              3,746
---------------------------------------------------------------------------------------------------------------------
TOTAL PROVED PLUS PROBABLE                  6,885             154          2,663          176             35,372
=====================================================================================================================
</TABLE>
(1)  Numbers may not add due to rounding. Based on estimates only. Variances may
     occur due to circumstances beyond Compton's control.

                                     - 30 -
<PAGE>

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

<TABLE>
<CAPTION>
=====================================================================================================================
                                                      FISCAL 2006 THREE MONTHS ENDED                    YEAR ENDED
                                         MARCH 31,       JUNE 30,    SEPTEMBER 30,     DECEMBER 31,     DECEMBER 31,
                                            2006           2006           2006            2006              2006
---------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/MCF)
<S>                                         <C>           <C>             <C>              <C>              <C>
Price                                        $7.64         $5.92           $5.41            $6.52            $6.37
Royalties                                   (1.79)        (1.31)          (1.15)           (1.47)           (1.43)
Operating costs(1)                          (0.98)        (1.03)          (1.25)           (1.30)           (1.14)
Transportation costs                        (0.15)        (0.15)          (0.15)           (0.15)           (0.15)
---------------------------------------------------------------------------------------------------------------------
Netback                                      $4.72         $3.43           $2.86            $3.60            $3.65

NATURAL GAS LIQUIDS ($/BBL)(2)
Price                                       $42.38        $52.37          $51.18           $40.61           $46.60
Royalties                                  (13.52)       (15.29)         (14.87)          (12.36)          (14.01)
Operating costs(1)                          (5.86)        (6.21)          (7.52)           (7.81)           (6.85)
Transportation costs                        (1.24)        (1.41)          (1.41)           (1.48)           (1.38)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $21.76        $29.46          $27.38           $18.96           $24.36

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)                          (9.96)       (10.59)         (13.11)          (14.08)          (11.87)
Transportation costs                        (1.24)        (1.41)          (1.41)           (1.48)           (1.38)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $34.55        $42.29          $38.26           $26.46           $35.63

TOTAL LIQUIDS ($/BBL)
Price                                       $53.62        $66.54          $63.96           $49.46           $58.53
Royalties                                  (12.48)       (16.97)         (15.91)          (11.68)          (14.29)
Operating costs(1)                          (8.84)        (9.39)         (11.50)          (12.15)          (10.44)
Transportation costs                        (1.24)        (1.41)          (1.41)           (1.48)           (1.38)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $31.06        $38.77          $35.14           $24.15           $32.42

TOTAL ($/BOE)
Price                                       $48.21        $44.85          $41.33           $41.82           $44.05
Royalties                                  (11.29)       (10.59)          (9.42)           (9.54)          (10.21)
Operating costs(1)                          (6.77)        (7.17)          (8.64)           (8.93)           (7.88)
Transportation costs                        (1.00)        (1.05)          (1.04)           (1.05)           (1.04)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $29.15        $26.04          $22.23           $22.30           $24.92
=====================================================================================================================
</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 sulphur.

                                     - 31 -
<PAGE>

<TABLE>
<CAPTION>
=====================================================================================================================
                                                     FISCAL 2005 THREE MONTHS ENDED                      YEAR ENDED
                                         MARCH 31,       JUNE 30,    SEPTEMBER 30,      DECEMBER 31,     DECEMBER 31,
                                            2005           2005           2005             2005             2005
---------------------------------------------------------------------------------------------------------------------
NATURAL GAS ($/MCF)
<S>                                        <C>           <C>             <C>              <C>              <C>
Price                                        $6.60         $7.28           $8.46           $11.20            $8.42
Royalties                                   (1.58)        (1.61)          (2.03)           (2.57)           (1.96)
Operating costs(1)                          (0.90)        (0.89)          (0.88)           (0.97)           (0.91)
Transportation costs                        (0.15)        (0.15)          (0.15)           (0.15)           (0.15)
---------------------------------------------------------------------------------------------------------------------
Netback                                      $3.97         $4.63           $5.40            $7.51            $5.40

NATURAL GAS LIQUIDS ($/BBL)(2)
Price                                       $39.40        $40.98          $56.08           $40.55           $44.08
Royalties                                  (12.09)       (12.42)         (18.38)          (12.20)          (13.71)
Operating costs(1)                          (5.42)        (5.36)          (5.26)           (5.79)           (5.46)
Transportation costs                        (0.50)        (1.35)          (1.80)           (1.57)           (1.33)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $21.39        $21.85          $30.64           $20.99           $23.58

CRUDE OIL ($/BBL)
Price                                       $50.17        $61.50          $68.98           $65.23           $62.02
Royalties                                  (11.06)       (13.51)         (16.17)          (15.84)          (14.35)
Operating costs(1)                         (10.12)        (9.89)          (9.50)           (9.93)           (9.86)
Transportation costs                        (0.50)        (1.35)          (1.80)           (1.57)           (1.33)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $28.49        $36.75          $41.51           $37.89           $36.48

TOTAL LIQUIDS ($/BBL)
Price                                       $46.23        $54.20          $64.75           $57.99           $56.04
Royalties                                  (11.44)       (13.12)         (16.90)          (14.77)          (14.13)
Operating costs(1)                          (8.40)        (8.28)          (8.11)           (8.72)           (8.39)
Transportation costs                        (0.50)        (1.35)          (1.80)           (1.57)           (1.33)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $25.89        $31.45          $37.94           $32.93           $32.19

TOTAL ($/BOE)
Price                                       $41.25        $46.33          $54.31           $64.58           $51.95
Royalties                                   (9.99)       (10.53)         (13.37)          (15.24)          (12.36)
Operating costs(1)                          (6.15)        (6.09)          (5.98)           (6.63)           (6.22)
Transportation costs                        (0.80)        (1.01)          (1.13)           (1.09)           (1.01)
---------------------------------------------------------------------------------------------------------------------
Netback                                     $24.31        $28.70          $33.83           $41.62           $32.36
=====================================================================================================================
</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 sulphur.

                                     - 32 -
<PAGE>

                                    DIVIDENDS

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

                                CAPITAL STRUCTURE

Compton  is  authorized  to issue an  unlimited  number of common  shares and an
unlimited number of preferred  shares,  of which  128,679,426  common shares are
issued and  outstanding as fully paid and  non-assessable  share as at March 26,
2007. No preferred  shares are issued and  outstanding as at March 26, 2007. The
following is a description of Company's common and preferred shares.

COMMON SHARES

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

PREFERRED SHARES

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

SHAREHOLDER RIGHTS PLAN

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

                                     - 33 -
<PAGE>

                              MARKET FOR SECURITIES

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

<TABLE>
<CAPTION>
=====================================================================================================================
             PERIOD                 TSX HIGH CLOSE        TSX LOW CLOSE          TSX AVERAGE DAILY TRADING VOLUME
---------------------------------------------------------------------------------------------------------------------
2006
<S>                                       <C>                  <C>                              <C>
  January                                 $18.84               $17.01                           743,850
  February                                $18.92               $14.39                           773,430
  March                                   $15.87               $13.95                           636,443
  April                                   $16.80               $15.20                           510,985
  May                                     $15.50               $12.80                           659,357
  June                                    $14.04               $11.78                           579,747
  July                                    $15.00               $12.53                           487,149
  August                                  $15.04               $13.17                           301,956
  September                               $13.62               $10.67                           390,923
  October                                 $12.42               $10.68                           632,137
  November                                $12.08               $10.95                           348,881
  December                                $12.00               $10.65                           477,180

2007
  January                                 $11.42                $9.57                           492,536
  February                                $11.40               $10.54                           322,984
  March 1-26                              $11.73               $10.22                           512,593
=====================================================================================================================
</TABLE>


                              CONFLICTS OF INTEREST

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


           INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

None of the current executive Officers or Directors of Compton, and no person or
company  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

                                     - 34 -
<PAGE>

indirectly,  in any  transaction  or proposed  transaction  that has  materially
affected or would materially affect Compton.


                               MATERIAL CONTRACTS

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

                              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
had, nor expected to receive, any of the Company's outstanding common shares.

                                     RATINGS

Standard & Poor's Rating Services  ("S&P") and Moody's  Corporation  ("MOODY'S")
have  rated  Compton's  U.S.  $450  million  7-5/8%  Senior  Notes  as B and  B2
respectively, as at December 31, 2006. A security rating is not a recommendation
to buy,  sell, or hold  securities and may be subject to revisions or withdrawal
at any time by the rating agency.

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

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

                                     - 35 -
<PAGE>

                             DIRECTORS AND OFFICERS

DIRECTORS

Information is given below with respect to each of the current  Directors of the
Company.  All Directors of Compton stand for election at each annual  meeting of
the Company.  The next Annual Meeting of  Shareholders  is scheduled for May 10,
2007 at 3:30 pm.  (Calgary time) in the Historical  Ballroom on the 4th Floor of
the Calgary  Chamber of Commerce,  517-Centre  Street South,  Calgary,  Alberta,
Canada.

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

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

<PAGE>

<TABLE>
<CAPTION>
=====================================================================================================================
NAME AND MUNICIPALITY OF                               PRINCIPAL OCCUPATION                           DIRECTOR SINCE
RESIDENCE
---------------------------------------------------------------------------------------------------------------------
<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.,
                              Enbridge  Technology Inc., and a director of numerous Enbridge Inc., a
                              pipeline  company,  affiliates,  including  those in Europe  and Latin
                              America.


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

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


                              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 with       1993
Calgary, AB, Canada           Sun Microsystems of Canada Inc., a computer company.
---------------------------------------------------------------------------------------------------------------------

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

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


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

                                     - 36 -
<PAGE>

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


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

Further  information  about the  Directors  and the  committees  of the Board of
Directors  is set  forth  under  the  heading  "Election  of  Directors"  in the
Company's  Management Proxy Circular dated March 12, 2007 relating to the Annual
Meeting  of  Shareholders  to be  held  on May  10,  2007,  which  sections  are
incorporated by reference into this Annual Information Form.

OFFICERS

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

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

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

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

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

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

As at  March  26,  2007,  the  Directors  and  Officers  of  Compton  as a group
beneficially  owned or  controlled,  directly or indirectly,  13,139,767  common
shares  of  Compton,   representing   approximately  10.2%  of  the  issued  and
outstanding common shares of the Company. None of the Directors or Officers held
a  sufficient  number of common  shares to  materially  affect  the  control  of
Compton.

                                     - 37 -
<PAGE>

                  AUDIT, FINANCE AND RISK COMMITTEE INFORMATION

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

COMPOSITION OF THE AUDIT, FINANCE AND RISK COMMITTEE

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

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

Mr.  Thomson is  considered  to be a "financial  expert," as defined in National
Instrument 52-110,  "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.

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,
2006 and 2005 were as follows:

==============================================================================
TYPE OF SERVICE                           FISCAL 2006       FISCAL 2005 (1)
------------------------------------------------------------------------------
Financial statement audit                     $ 510,360           $451,899
Internal controls audit                         489,000                  -
Audit related                                    69,220            184,022
Tax                                               8,795             14,200
Other non-audit                                  37,240             44,780
------------------------------------------------------------------------------
Total                                        $1,114,615           $694,901
==============================================================================

(1)  2005 amounts have been updated to account for  differences  between accrued
     costs and actual billings.

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 related fees  incurred in fiscal 2005 related to the Company's  equity
offering in February  2005 and the issuance of the  Company's  U.S.$300  million
dollar senior notes in November  2005.  Tax fees incurred in fiscal 2005 related
to the review of tax forms and the fees for other  non-audit  services in fiscal
2005 were incurred to translate the Company's  quarterly and annual reports into
French.

The Audit,  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

                                     - 38 -
<PAGE>

provided to the  Company by Grant  Thornton  LLP and in such
case, only with the prior approval of the Audit, Finance and Risk Committee. The
Committee has  pre-approved  Management to retain Grant  Thornton LLP to provide
miscellaneous,  minor,  non-audit  services  in  circumstances  where  it is not
feasible  or  practical  to  convene a meeting of the  Audit,  Finance  and Risk
Committee, subject to an aggregate limit of $20,000 per quarter.


                          TRANSFER AGENT AND REGISTRAR

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


                             ADDITIONAL INFORMATION

Additional   information   including  Directors'  and  Officers'   remuneration,
principal  holders of the Company's  common  shares,  options to acquire  common
shares,  and interests of insiders in material  transactions  (if applicable) is
contained in the Management  Proxy Circular issued by Management dated March 12,
2007,  relating to the Annual and Special  Meeting of Shareholders to be held on
May  10,  2007.  Additional  financial  information  is  also  provided  in  the
consolidated  financial  statements  and MD&A of the  Company for the year ended
December 31, 2006, included in the Company's 2006 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

                                     - 39 -
<PAGE>

[LOGO OMITTED] NSAI - NETHERLAND, SEWELL & ASSOCIATES, INC.

                                   SCHEDULE A
                                 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 and audited the  Company's  reserves data as at December
     31, 2005, as follows:

     (a)  (i)    Evaluated  the  proved  and proved  plus  probable  oil and gas
                 reserves  as at December  31,  2006,  of the major  properties,
                 using forecast prices and costs; and

         (ii)    the related estimated future net revenue; and

     (b)  (i)    Evaluated  and  proved  and proved  plus  probable  oil and gas
                 reserves  as at December  31,  2006,  of the major  properties,
                 using constant prices and costs; and

         (ii)    the related estimated future net revenue.

     (c)  (i)    Audited  the  proved  and  proved  plus  probable  oil  and gas
                 reserves  as at December  31,  2006,  of the minor  properties,
                 using forecast prices and costs; and

         (ii)    the related estimated future net revenue; and

     (d)  (i)    Audited  the  proved  and  proved  plus  probable  oil  and gas
                 reserves  as at December  31,  2006,  of the minor  properties,
                 suing constant prices and costs; and

         (ii)    the related estimated future net revenue.

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

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

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

4.   The  following  table sets forth the estimated  future net revenue  (before
     deduction of income taxes)  attributed  to proved plus  probable  reserves,
     estimated using forecast  prices and costs and calculated  using a discount
     rate of 10 percent,  included in the reserves data of the Company evaluated
     by us for the year ended  December 31, 2005,  and identifies the respective
     portions  thereof that we have audited,  evaluated,  and reported on to the
     company's board of directors.

<TABLE>
<CAPTION>
                                                Location of             (before Canadian Audited Income taxes,
                         Description and          Reserves                      10% discount rate) (MCS)
Independent Qualified  Preparation Date of  (Country or Foreign   -------------------------------------------------
 Reserves Evaluator     Evaluated Report      Geographic Area)    Audited       Evaluated      Reserved       Total
-------------------------------------------------------------------------------------------------------------------

<S>                      <C>                      <C>             <C>           <C>              <C>      <C>
Netherland, Sewel &
Associates, Inc.         March 7, 2007            Canada          226,276       2.616,801        nil      2,645,077
</TABLE>

                                     - 40 -
<PAGE>

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

6.   We have no  responsibility to update our reports referred to in paragraph 4
     for events and circumstances  occurring after their respective  preparation
     dates.  Although  this report was printed March 7, 2007, it was based on an
     effective date of December 31, 2005.

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

Executed as to our report referred to above:

                                      NETHERLAND, SEWELL & ASSOCIATES, INC.
                                      Dallas, Texas, USA
                                      March 20, 2007



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

PCB:MBB

================================================================================

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

================================================================================

                                     - 41 -
<PAGE>


                                   SCHEDULE B

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

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

        (a)    (i)   proved and proved plus  probable oil and gas reserves as at
                     December 31, 2006 using forecast prices and costs; and

              (ii)   the related estimated future net revenue; and

        (b)    (i)   proved and proved plus  probable oil and gas reserves as at
                     December 31, 2006 using constant prices and costs; and

              (ii)   the related estimated future net revenue.

An  independent  qualified  reserves  evaluator has evaluated (in respect of the
Company's  major  properties)  and audited (in  respect of the  Company's  minor
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
              the reserves data and other oil and gas information;

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

        (c)   the content and filing of this report.

                                     - 42 -
<PAGE>

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


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

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

March 26, 2007

                                     - 43 -
<PAGE>

                                   SCHEDULE C

                CHARTER OF THE AUDIT, FINANCE AND RISK COMMITTEE


MANDATE OF THE COMMITTEE

The  Audit,  Finance  and  Risk  Committee  (the  "COMMITTEE")  of the  Board of
Directors (the "BOARD") of Compton Petroleum  Corporation (the "COMPANY") shall,
as permitted by the Business  Corporations  Act  (Alberta)  (the "ABCA") and the
Articles and By-Laws of the  Company,  have the  responsibility  to oversee that
management  has applied due diligence in creating and  maintaining  an effective
risk management and control framework.  This framework should provide reasonable
assurance that the  financial,  operational,  and  regulatory  objectives of the
Company are achieved and that the  statutory  responsibilities  of the Board are
discharged.  The  Committee  fulfills  its  role  on  behalf  of the  Board,  by
overseeing:

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

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

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

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

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

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

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

In fulfilling  its mandate,  the Committee has the  responsibility  to,  without
limitation:

(A)     INTERNAL AND DISCLOSURE CONTROLS

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

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

                                     - 44 -
<PAGE>

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

4.      review,   in  conjunction  with  the  Human   Resources,   Compensation,
        Environmental, Health and Safety Committee of the Board, the appointment
        of the Chief Financial Officer;

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

6.      review with management and the external auditor:

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

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

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

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

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

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

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

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

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

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

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

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

                                     - 45 -
<PAGE>

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

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

        (c)   any other obligations arising from certification, and

        (d)   any significant changes in the internal controls;

13.     review with  management and the external  auditor and as required by the
        Corporate Governance  Committee,  the Company's Code of Business Conduct
        and Ethics;

14.     establish and maintain procedures for:

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

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

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

(B)     OVERSIGHT OF THE EXTERNAL AUDITOR

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

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

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

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

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

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

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

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

                                     - 46 -
<PAGE>

9.      review  all  issues and  documentation  related to a change of  external
        auditor,  including  information to be included in the Change of Auditor
        Notice and documentation  called for under National  Instruments  51-102
        and the planned steps for an orderly transition period;

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

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

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

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

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

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

(C)     OVERSIGHT OF FINANCIAL REPORTING AND ACCOUNTING POLICIES

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

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

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

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

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

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

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

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

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

                                     - 47 -
<PAGE>

(D)     ADDITIONAL DUTIES AND RESPONSIBILITIES

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

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

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

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

(E)     GENERAL

The Committee also has the responsibility to:

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

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

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

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

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

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

7.      fulfill its responsibilities and duties by:

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

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

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

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

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

                                     - 48 -
<PAGE>

COMPOSITION OF THE COMMITTEE

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

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

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

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

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

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

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

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

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

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

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

        (c)   At least one  member of the  Committee  shall have  accounting  or
              related  financial  management  expertise and, where possible,  at
              least  one  member of the  Committee  shall  qualify  as an "audit
              committee  financial  expert"  within the  meaning  of  applicable
              securities legislation.

MEETINGS OF THE COMMITTEE

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

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

3.      Notice of a meeting of the Committee shall:

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

                                     - 49 -
<PAGE>

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

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

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

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

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

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

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

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

                                     - 50 -
<PAGE>

                          COMPTON PETROLEUM CORPORATION
                            STANDARDS OF INDEPENDENCE

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

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

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

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

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

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

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

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

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

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

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

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

                                     - 51 -
<PAGE>

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

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




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

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

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

(3)   Affiliated person of another person means:

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

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

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

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

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

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



                                     - 52 -