**Exhibit 20.1**

 

 

 

 

**ANNUAL INFORMATION FORM**

**For the Year Ended December** **31, 2008**

 

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March 23, 2009

 

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**TABLE OF CONTENTS**

 

|                                                                                | **Page** |
|-------------------------------------------------------------------------------------|----------|
| ABBREVIATIONS AND CONVERSION FACTORS                                                | 2        |
| DEFINITIONS                                                                         | 3        |
| ADVISORIES                                                                          | 8        |
| CORPORATE STRUCTURE                                                                 | 9        |
| GENERAL DEVELOPMENT OF THE BUSINESS                                                 | 10       |
| DESCRIPTION OF THE BUSINESS                                                         | 11       |
| RISK FACTORS                                                                        | 16       |
| STATEMENT OF RESERVES DATA                                                          | 22       |
| DIVIDENDS                                                                           | 35       |
| CAPITAL STRUCTURE                                                                   | 35       |
| MARKET FOR SECURITIES                                                               | 36       |
| CONFLICTS OF INTEREST                                                               | 37       |
| INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS                         | 37       |
| CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS                            | 37       |
| MATERIAL CONTRACTS                                                                  | 38       |
| LEGAL PROCEEDINGS AND REGULATORY ACTIONS                                            | 38       |
| INTERESTS OF EXPERTS                                                                | 39       |
| RATINGS                                                                             | 39       |
| DIRECTORS AND OFFICERS                                                              | 39       |
| AUDIT, FINANCE AND RISK COMMITTEE INFORMATION                                       | 42       |
| TRANSFER AGENT AND REGISTRAR                                                        | 44       |
| ADDITIONAL INFORMATION                                                              | 44       |
|                                                                                |     |
| SCHEDULE A REPORT ON RESERVES DATA                                                  | 45       |
| SCHEDULE B REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES ON OIL AND GAS DISCLOSURE | 47       |
| SCHEDULE C COMPTON PETROLEUM CORPORATION AUDIT, FINANCE AND RISK COMMITTEE          | 49       |

 

 

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**ABBREVIATIONS AND CONVERSION FACTORS**

**Abbreviations**

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

“**bbl**” means barrel;

“**bbl/d**” means barrels per day;

“**bbls**” means barrels;

“**boe**” means barrels of crude oil equivalent;

“**boepd**” or “**boe/d**” means barrels of crude oil equivalent per day;

“**km2**” means square kilometres;

“**lt**” means long ton;

“**Mbbls**” means thousand barrels;

“**Mboe**” means thousand barrels of crude oil equivalent;

“**Mcf**” means thousand cubic feet;

“**Mcfe**” means thousand cubic feet equivalent;

“**mi**” means miles;

“**mi2**” means square miles;

“**Mlt**” means thousands of long tons;

“**MMbbls**” means million barrels;

“**MMBoe**” means million barrels of crude oil equivalent;

“**MMbtu**” means million British thermal units;

“**MMcf**” means million cubic feet;

“**MMcfd**” or “**MMcf/d**” means million cubic feet per day;

“**MMcfe**” means million cubic feet equivalent; and

“**ngls**” means natural gas liquids.

 

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**Conversion Factors**

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

 

| **To Convert From** | **To**              | **Multiply By** |
|---------------------|---------------------|-----------------|
| boe                 | Mcfe                | 6.000           |
| cubic feet          | cubic metres of gas | 0.028           |
| cubic metres of gas | cubic feet          | 35.490          |
| bbls of oil         | cubic metres        | 0.159           |
| cubic metres        | bbls of oil         | 6.289           |
| feet                | metres              | 0.305           |
| metres              | feet                | 3.281           |
| miles               | kilometres          | 1.609           |
| kilometres          | miles               | 0.621           |
| acres               | hectares            | 0.400           |
| hectares            | acres               | 2.500           |

 

**DEFINITIONS**

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

“**AIF**” means this Annual Information Form.

“**associated gas**” means the gas cap overlying a crude oil accumulation in a reservoir.

“**Company**” or “**Compton**” or “**we**” means Compton Petroleum Corporation and its partnership and subsidiaries where the context so requires.

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

“**developed non-producing**” reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

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

 

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

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

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

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

|   | (d) | provide improved recovery systems. |
|--------|-----|------------------------------------|

“**development well**” means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

“**EUB**” means the Alberta Energy and Utilities Board.

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

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

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

|   | (c) | dry hole contributions and bottom hole contributions; |
|--------|-----|-------------------------------------------------------|

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

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

“**exploratory well**” means a well that is not a development well, a service well, or a stratigraphic test well.

 

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“**FD&A**” means finding, development and acquisition costs, which are used as a measure of capital efficiency.

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

“**forecast prices and costs**” means future prices and costs that are:

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

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

“**future income tax expenses**” means future income tax expenses estimated year-by-year:

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

|   | (b) | without deducting estimated future costs that are not deductible in computing taxable income; |
|--------|-----|-----------------------------------------------------------------------------------------------|

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

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

“**future net revenue**” means the estimated net amount to be received with respect to the development and production of reserves estimated using forecast prices and costs.

“**gross**” means:

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

|   | (b) | the total number of wells in which the Company has an interest; and |
|--------|-----|---------------------------------------------------------------------|

|   | (c) | the total area of properties in which the Company has an interest. |
|--------|-----|--------------------------------------------------------------------|

“**liquids**” means crude oil, natural gas liquids, and sulphur.

 

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

|   | (b) | the number of wells obtained by aggregating the Company’s working interest in each of its gross wells; and |
|--------|-----|------------------------------------------------------------------------------------------------------------------|

|   | (c) | the total area of properties in which the Company has an interest multiplied by the working interest owned by the Company. |
|--------|-----|----------------------------------------------------------------------------------------------------------------------------|

“**non-associated gas**” means an accumulation of natural gas in a reservoir where there is no crude oil.

“**operating costs**” or “**production costs**” means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related            equipment and facilities.

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

“**production**” means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.

“**property**” includes:

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

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

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

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

 

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“**property acquisition costs**” means costs incurred to acquire a property (directly by purchase or lease or indirectly by acquiring another corporate entity with an interest in the property) including:

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

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

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

“**proved**” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

“**proved property**” means a property or part of a property to which reserves have been specifically attributed.

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

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

“**section**” means one square mile or 640 acres.

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

“**shut-in well**” means a well which is capable of economic production or which the Company considers capable of production but which for a variety of reasons, including, but not limited to, lack of markets or development, is not placed on production at the present time.

“**solution gas**” means gas dissolved in crude oil.

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

“**support equipment and facilities**” means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps and division, district, or field offices.

 

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

“**unproved property**” means a property or part of a property to which no reserves have been specifically attributed.

“**well abandonment costs**” means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. Costs of abandoning the gathering system or reclaiming the well site are not included.

**ADVISORIES**

**Use of BOE Equivalents**

The oil and natural gas industry commonly expresses production volumes and reserves on a 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, ngls, and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. In several sections that            follow, Compton has used the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip and does not represent a value equivalency at the wellhead. However, this does not represent a value equivalency at the plant gate where Compton sells its production volumes and therefore may be a misleading measure if used in isolation.

**Forward-Looking Statements**

Certain information regarding the Company contained herein constitutes forward-looking information and statements under the meaning of applicable securities laws, including CSA’ “National Instrument 51-102 Continuous Disclosure Obligations” and the United States’ “Private Securities Litigation Reform Act of 1995”. Forward-looking statements include assumptions,            estimates, plans, expectations, opinions, forecasts, projections, guidance, or other statements that are not statements of fact, including statements regarding (i) cash flow, production estimates, reserve estimates, capital expenditures, operating expenditures, drilling program, tax estimates, total future net revenue, pricing assumptions, abandonment and reclamation costs, and (ii) other risks and uncertainties described from time to time in the reports and filings made by Compton            with securities regulatory authorities. Although Compton believes that the expectations and assumptions reflected in such forward-looking statements are reasonable, it can give no assurance that such assumptions and expectations will prove to have been correct. There are many factors that could cause forward-looking statements not to be correct, including risks and uncertainties inherent in the Company’s business. These risks include, but are not limited to: crude oil and            natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards, access difficulties and mechanical failures, weather related issues, uncertainties in the estimates of reserves and in projection of future rates of production and timing of development expenditures, general economic conditions, and the actions or inactions of third-party operators, and other risks set forth in the “Risk Factors” section of this AIF.            Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and can be profitably produced in the future. Compton may, as considered necessary in the circumstances, update or revise forward-looking information, whether as a result of new information, future            events, or otherwise, but Compton does not undertake to update this information at any particular time, except as required by law. The Company’s forward-looking statements are expressly qualified in their entirety by this cautionary 

 

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statement. Compton cautions readers that the forward-looking statements may not be appropriate for purposes other than their intended purposes and that undue reliance should not be placed on any forward-looking statement.

**CORPORATE STRUCTURE**

**Name and Incorporation**

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

The Company’s head and principal office is located at Suite 3400, 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 Compton’s production activities are carried out through this partnership.

Compton Petroleum Finance Corporation, formed under the laws of Alberta, is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Petroleum Finance Corporation has no independent  operations  and  has  no significant liabilities or  assets  other  than  US$450  million of  7 5/8% Senior Notes issued by            Compton Petroleum Finance Corporation, its equity interest in Hornet Energy Ltd. and intercorporate indebtedness. The registered office of Compton Petroleum Finance Corporation is 4300 Bankers Hall West, 888 – 3rd Street S.W., Calgary, Alberta, Canada, T2P 5C5.

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

 

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The consolidated financial statements include the accounts of Compton Petroleum Corporation 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**

Compton is active in three deep basin natural gas development plays: the Basal Quartz sands at Hooker in southern Alberta, the Gething/Rock Creek sands at Niton and Caroline in central Alberta, and the shallower Plains Belly River sand play in southern Alberta. In addition, the company has one exploratory play in the Foothills area of southern Alberta, which is a thrusted over-pressured Belly River            sand formation at Callum/Cowley/Todd Creek.

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

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

In 2008, activities were directed towards the continued development of the Company’s core natural gas resource plays in southern and central Alberta. Compton applied horizontal well and multiple stage fracture stimulation technology at several of its key properties. Compton’s management (“**Management**”) believes that this            technology is particularly applicable to the deep basin assets and has the potential to increase ultimate recovery and improve development economics. Compton currently has 32 horizontal gas wells that have been multi-staged fractured – the majority of which were drilled and placed on production in 2008. Approximately 144% of the Company’s 2008 production was replaced at a proved FD&A of $20.29/boe, excluding technical revisions. In addition, Compton continued to            divest non-focus asset areas and, as such, Cecil, Zama, Thornbury and the Peace River Arch assets were sold for net 

 

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proceeds of $203 million, resulting in a reduction of 305,606 net acres. All proceeds from the divestments were used to pay down debt. Compton completed one minor acquisition during the year that came as a result of a property swap with the buyer of Compton’s Cecil assets.

**DESCRIPTION OF THE BUSINESS**

**Business Plan and Operating Strategy**

The Company’s business plan is to increase shareholder value through the effective exploration, development and exploitation of its core geographic areas and by making accretive strategic acquisitions. This will be achieved through the evaluation of the benefits of various opportunities and pursuit of those that provide the optimal return, maximizing cash flow and asset value. 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:

*Pursue High Return Activities to Maximize Shareholder Value*. Compton will utilize a disciplined business model to focus on value creation when reinvesting internally generated cash flow, providing the Company and shareholders with optimal returns. This perspective will be utilized in the evaluation and selection of prospects, which include development activities to            maximize the value of its strong asset base or responding to future growth opportunities. In 2009, Compton will develop a robust five-year plan that provides a strategic direction and plan for future value.

*Concentrate on Core Areas*. Compton is focused on its core areas, which provide a solid 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 evaluate            exploration opportunities and to increase the Company’s undeveloped land base within the WCSB.

*Focus on Unconventional Natural Gas in Large Resource Plays*. 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 large scale types of natural gas opportunities because of their generally            longer life and lower exploration risk compared to conventional natural gas opportunities.

*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.

*Implement Measured and Flexible Financial Approach*. The Company has initiated a corporate restructuring process with a concentrated emphasis on maximizing capital efficiencies and reducing internal cost structures. Compton will take a flexible financial approach, adjusting its 2009 capital spending up or down, depending upon how economic circumstances unfold during the            year, and intends to limit capital expenditures to within funds flow from operations. This will provide financial flexibility required to pursue full-cycle exploration programs in periods of low commodity prices and act on 

 

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strategic acquisitions. Other components of Compton’s financial discipline include establishing appropriate leverage ratios and maintaining an active commodity hedging program.

**Principal Properties**

Compton engages in oil and gas exploration and development in the WCSB in Alberta, Canada. In this large geographical region, Compton’s primary focus is on the deep basin portion of the WCSB which extends from Northwest Alberta and British Columbia to the United States border, where predictable development results at low risk can be achieved. Compton has three deep basin development gas plays:            the Basal Quartz sands at Hooker in southern Alberta, the Gething/Rock Creek sands at Niton and Caroline in central Alberta and the shallower Plains Belly River sand play in southern Alberta. In addition, the company has one exploratory play in the Foothills area of southern Alberta, which is a thrusted over-pressured Belly River sand formation at Callum/Cowley/Todd Creek.These areas are the geographic focus of Compton’s seismic database and are areas in which Management and            staff have significant technical expertise and operational experience.

**Development Properties**

***Hooker (Southern Alberta)***

Discovered by Compton in 1999, the Hooker asset is a low to medium permeability Basal Quartz channel sandstone pool, which is the southern Alberta extension of the Lower Cretaceous Deep Basin gas trend.

Compton controls 165 sections at an average 85% working interest in this area. In February 2008, this large pool reached a production milestone of 100 BCF. The pool is currently producing 36.1 MMcf/d from the Basal quartz formation in 102 wells over five townships. With an annual pool wide base decline of 15%, the pool is a legacy asset with a predictable, stable, water free decline producing liquids            rich gas.

Compton initiated horizontal drilling with multi-stage fracture stimulations in the pool with the drilling of one well in late 2007 and an additional four wells in 2008. The successful application of this technology could allow Compton to improve depletion economics, particularly in the tight early stage parts of the reservoir.

The Hooker play has historically been developed through drilling one to two vertical wells per section. Reservoir modeling indicates up to four vertical wells per section may be necessary to fully develop the play. In 2008, Compton successfully negotiated, with the sole remaining partner in the pool, to down space 45 of 57 developed sections to three wells per section. This will provide more latitude            when establishing optimal well densities in order to maximize value of the company’s depletion strategy. The 12 remaining sections have sufficient drainage with current well densities to adequately access the reservoir.

In 2009, Compton intends to optimize its existing gas producers and continue its drilling success by drilling one to three horizontals in addition to select vertical locations. A key component of success in this area will be to minimize drilling and completion costs. Through selective drilling and pool wide optimization, Hooker’s depletion strategy can be optimized to enhance capital            efficiency.

***Niton and Caroline (Central Alberta)***

The Niton and Caroline area is a multi-zone liquids rich, tight gas play with production primarily coming from Jurassic Rock Creek, and Mannville Ellerslie/Gething sands. Proprietary exploration, development, and operational knowledge gained by the Company in southern Alberta has resulted in accelerated growth 

 

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of this core area. Compton has drilled approximately 144 wells to date on its 265 sections of controlled land in this area at a 75% working interest.

Compton experienced significant drilling success in 2008: 25 wells were drilled, including 12 horizontal wells in the Rock Creek formation and 2 horizontal wells targeting the Ellerslie formation.

The Rock Creek play’s variable permeability and water-free nature lends itself well to horizontal drilling and multistage fracturing. Compton is the leading Niton operator developing this play with 23 successful horizontal wells producing from this zone at year-end. The typical horizontal Rock Creek well has an average initial rate of 3 Mmcf/d in the first month of production, which contributes            to play economics. In 2008, a joint venture farm-in was completed to earn a further nine sections of land on this Rock Creek play, where three vertical and two horizontal Rock Creek wells were drilled during the year. In addition, the Edson 5-26-52-17W5M compressor station was expanded from 10 to 20 MMcf/d during 2008 to provide additional capacity for production increases.

The Ellerslie formation is an under-pressured, essentially water-free, tight channel sand complex that is similar to our Hooker play, ranging in depth from 1,950 to 2,300 metres. Historically, these sands have only been developed through vertical drilling. Compton evaluated the application of new technology in 2008, drilling two horizontal wells targeting lower permeability sands in this zone. Both            wells are on production with an average production rate of 670 Mcf/d as a first month initial rate. Older offset vertical wells, adjacent to Compton’s horizontals, had limited productive capability.

In the second half of 2009, Compton may continue with development operations in Niton targeting more permeable sands in the Rock Creek and Ellerslie formations, should commodity prices and drilling costs support investment returns.

***Plains Belly River and Edmonton Group (Southern Alberta)***

The Plains Belly River and overlying Edmonton Horseshoe Canyon shallow gas zones consists of an under-pressured, essentially water-free, multi-sand zone that averages 450 metres in thickness per zone, totalling over 900 metres in thickness. The entire 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.

Compton has over one hundred low risk development locations surveyed and licensed in the Plains Belly River and Edmonton Group. With control of 1,190 sections of land at an average 90% working interest, this land base translates to a significant multi-year, low risk drilling inventory at four wells per section.

In 2008 Compton drilled 160 gross Belly River development wells. At year-end, the company was producing 45 MMscf/d from 750 wells. Ample infrastructure is in place in the area for future production increases with 32,500 horsepower of compression and approximately 1,300 kilometres of pipeline.

In 2009, Compton will focus on optimizing existing pipeline systems and compressors, while initiating workovers, licensing additional drilling locations and undertaking re-completions on select wells. In addition, operating costs will be reduced wherever possible in order to improve the economics of this play in the current low commodity price environment. Once gas prices improve, Compton can            commence infill drilling to fill existing compression. On a go forward basis, Compton anticipates that the majority of its lands will be developed at the government approved spacing of four wells per section on this shallow low risk gas play.

 

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**Exploratory Properties**

***Callum-Cowley & Todd Creek (Southern Alberta)***

Compton controls 214 sections at an average 95% working interest, and has drilled 17 wells to date in the Foothills area of southern Alberta.

The Callum-Cowley area is unique in western Canada consisting of a series of over-pressured, thrusted, low permeability, water-free Belly River sands. This play is largely exploratory at this time.

Based on Compton’s initial detailed geological, geophysical, and engineering analysis of seismic, cores, well logs, and test and production data, Callum-Cowley appears to exhibit many similarities to the deep unconventional gas pools of the Rocky Mountain region of the United States.

In 2008, Compton drilled and fracture stimulated two horizontal wells, targeting select thrusted Belly River sands. The use of 3-D seismic was essential to effectively target the structurally complex fractured sands, following individually mapped fractured Belly River channels. The wells are following the typical production profile for tight horizontal gas sands. Well licenses, surface leases and            pipelines have been obtained for three additional Callum-Cowley locations.

At Todd Creek, Compton is pursuing an exciting new exploratory play. In 2008, a new zone was successfully completed in an older existing wellbore. A pipeline was installed late in December 2008 to tie-in the well; initial production was 4 MMcf/d but it is currently being restricted to 2.5 MMscf/d in order to provide sufficient test data on this new exploratory concept. Future activities will be            somewhat dependent on production results from the well as this property is in the early stages of development. A follow up location has been licensed and may be drilled in the third quarter of 2009.

**Principal Markets and Distribution Methods**

Compton’s natural gas production is sold under a combination of longer term contracts with aggregators and short term daily or monthly indexed contracts. Approximately 10% of the Company’s natural gas production in 2008 was committed to aggregators, compared to an average of 10% in 2007. The average aggregator price realized in 2008 was $1.00/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 favourable pricing. The Company sells crude oil and ngls primarily to refineries and marketers of crude oil and natural gas liquids. Liquids may be transported through regulated pipelines or trucked to the            point of sale.

**Cycles**

The petroleum industry is cyclical in nature. The winter-summer cycle affects certain aspects of the business such as commodity prices and ability to drill as related to spring break-up. The price per barrel received by the company is weighted to world natural gas commodity price and can be adversely affected by mild weather conditions. In the second half of 2008, higher supplies reduced world            commodity prices and resulted in a decrease in the price received by Compton.

 

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**Environmental Policies**

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

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

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 2009. 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. The quantitative assessment along with qualitative discussion in respect to environmental protection requirements, policies and costs can be            found in “Statement of Reserves Data – Additional Information Concerning Abandonment and Reclamation Costs” in this AIF.

**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.

Compton is in the process of renewing the management and processing agreements mandating terms of the MPP and all documents related to the agreements, which are scheduled to expire April 30, 2009. The company expects that the agreement will be renewed with few material changes.

 

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**Contracts**

Compton’s bank debt is composed of a syndicated, extendable, revolving credit facility with a current authorized limit of $500 million. This facility was renewed on July 2, 2008 under substantially identical terms and conditions except that certain syndicate members, representing $90 million of the authorized amount of $500 million, elected not to extend their participation beyond July 2, 2009.            The next scheduled annual review of the facility will occur in late spring 2009; if not extended at that time, amounts then outstanding under the facility are due July 3, 2010. Additionally, should the four remaining syndicate members, three of which are Canadian chartered banks, not increase their participation or new syndicate participants not be secured, the authorized amount would be reduced to $410 million or such other amount as the syndicate determines. The facility is a            borrowing-based facility with the borrowing base being determined by the syndicate based primarily on year-end reserves and giving effect to the banks’ commodity price assumptions. As at December 31, 2008 the company had drawn $290 million on the facility.

The amount that may be drawn on the syndicated facility is limited by a provision contained in the Trust Indenture related to the company’s senior notes. The provision limits secured debt to an amount not to exceed an Adjusted Consolidated Net Tangible Asset Value (“**ACNTA**”), as defined in the Indenture. The ACTNA calculation is made            quarterly and is based upon year-end reserves utilizing December 31, 2008 constant dollar prices. A preliminary ACNTA calculation at December 31, 2008 indicates that drawings on the company’s secured debt may be limited to approximately $375 million as a result of this provision.

**Specialized Skills and Knowledge**

Exploration for and development of petroleum and natural gas resources requires specialized skills and knowledge, including in the areas of petroleum engineering, geophysics, geology and land. Compton has obtained personnel with the required specialized skills and knowledge to carry out their respective operations. While the current labour market in the industry is highly competitive, the Company            expects to be able to attract and maintain appropriately qualified employees for 2009.

**Employees**

As at December 31, 2008, Compton had 176 full-time employees in its Calgary office and 63 full-time employees at field locations.

**Competitive Conditions**

Competitive conditions affecting the oil and gas industry are described under the heading “Competition” in the “Risk Factors” section of this AIF.

**RISK FACTORS**

**Volatility of Prices, Markets, and Marketing Production**

Oil and gas prices have historically been extremely volatile. 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.

 

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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.

Current market conditions are particularly challenging with the global recession negatively impacting commodity prices as well as access to credit and capital markets. These conditions impact Compton’s customers and suppliers and may alter Compton’s spending and operating plans. There may be unexpected business impacts from this market uncertainty.

 

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 Compton’s capacity to borrow funds. The Company’s secured credit facilities are based upon the lenders’ estimate of the value of the Company’s proved reserves, which determines the borrowing amount. A reduction in the quantity or value of reserves may also obligate Compton to            make additional payments under the processing agreement with MPP.

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

**Need to Replace Reserves**

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

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 

 

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

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

In addition, estimates of reserves, and future net cash flows expected there from, 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

 

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and hazards. The Company cannot fully protect against all of these risks, nor are all of these risks insurable. Compton may become liable for damages arising from these events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. The occurrence of a significant event not fully insured or indemnified against could seriously harm            Compton’s financial condition and operating results.

**Competition**

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

**Availability of Drilling Equipment and Access Restrictions**

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

Exploration and development activities also depend on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Increased demand for that equipment or imposed access restrictions may affect the availability of equipment to the Company and may delay exploration and development activities. In addition, to the extent that Compton is not the            operator of transportation facilities and pipelines, it will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.

**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. Continued uncertainty in domestic and            international credit markets compounds the risk of obtaining debt financing. 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 

 

 

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any employees. Compton’s success will be dependent upon its ability to continue to employ and retain skilled personnel.

 

**Changes to the Alberta Royalty Regime**

On January 1, 2009 the *Mines and Minerals (New Royalty Framework) Amendment Act*, *2008*became law. This legislation implements a new royalty framework (the “**New Royalty Framework**”) in Alberta which involves an increase in the            royalties collected by the Alberta government and changing the royalty structure for natural gas and conventional oil by adjusting the current sliding rate formulae that are price and volume sensitive. On November 19, 2008 the government of Alberta announced that it will be providing companies with a one-time option to select new transitional royalty rates, on a well-by-well basis, to companies that are drilling new natural gas or conventional oil wells (between 1,000 and 3,500            metres deep) after January 1, 2009. All wells that are drilled between 2009 and the end of 2013 that adopt the transitional rates will be required to shift to the New Royalty Framework on January 1, 2014. All current wells moved to the New Royalty Framework on January 1, 2009.

In addition, on March 3, 2009 the Alberta government announced a three-point incentive program to encourage additional activity in the province’s oil and gas sectors. The program applies to wells drilled between April 1, 2009 and March 31, 2010 and provides (i) a $200 per metre royalty credit for new wells and (ii) a maximum royalty rate of 5% on such wells for the first 12 months of production            up to a maximum of 50,000 barrels of oil or 500 million cubic feet of natural gas. This program will be in effect until March 31, 2011 and will be assessed as required as to whether it is necessary or appropriate to continue it. It is expected that the program will have the effect of reducing Compton’s royalties but the magnitude of this reduction is unknown. Given the recent changes to Alberta’s royalty regime, it is not possible to predict if and when any future            changes may occur.

**Environmental Risks**

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

Furthermore, future changes in environmental laws and regulations, including adoption of stricter standards or more stringent enforcement, could result in curtailment of production or materially increased costs, such as fines, incurred liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on Compton’s financial condition. For            example, Canada is a signatory to the United Nations’ Framework Convention on Climate Change and has ratified the Kyoto Protocol established there under to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide, and other so-called “greenhouse gases.” On June 22, 2007, the *Kyoto Protocol Implementation Act*received royal assent and was implemented to ensure that Canada            meets its global climate change obligations under the Kyoto Protocol though a yearly Climate Change Plan prepared by the Minister of Environment which will set out measures by which Canada will meet its obligations. On March 10, 2008 the federal government released its plan “*Turning the Corner: Regulatory Framework for Industrial Greenhouse Gas Emissions*,” which is an action plan to reduce greenhouse gases from 2006            levels by an absolute 20% by 2020 and by 60% to 70% by 2050. The 

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regulatory framework for industrial greenhouse gas emissions is being translated into regulation and is expected to come into force on January 1, 2010. As Compton’s production facilities and other operations and activities emit greenhouse gases, this plan will subject Compton to these emissions targets and may subject the Company to legislation that will require increasingly strict regulation            with respect to the emissions of greenhouse gases.

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

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

|   | **•** | Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force – on March 8, 2007, the Government of Canada and the Province of Alberta announced the formation of the Task Force to recommend the best ways for Canada to implement technology to capture carbon dioxide and store it deep underground. The final report of the Task Force was released                            on January 31, 2008 which recommended, among other things: (i) incorporating carbon capture and storage into federal and provincial greenhouse gas legislation; (ii) allocating new funding into projects through a competitive process; and (iii) targeting research to lower the cost of carbon capture technology. In March 2008 the Alberta government announced the formation of the Alberta Carbon Capture and Storage Development Council to develop a clear work path for                            implementing carbon capture and storage in Alberta, along with timing and expectations; |
|--------|------------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|   | **•** | Alberta’s *Climate Change and Emissions Management Act*& *Specified Gas Emitters Regulation*(which came into effect on July 1, 2007) outline emission reduction guidelines, including requiring Alberta facilities emitting more than 100,000                            tonnes of greenhouse gases a year to reduce their emissions intensity. Companies meet their reduction requirements by: (i) making operating improvements; (ii) purchasing Alberta-based emissions offsets; and/or (iii) acquiring fund credits by making contributions to the Climate Change and Emissions Management Fund; |
|--------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|   | **•** | Alberta’s*2008 Climate Change Strategy: Responsibility/Leadership/Action*– on January 24, 2008, the Alberta Government announced a new climate change action plan that is intended to cut Alberta’s projected greenhouse gas emissions in half by 2050. The plan focuses on (i) carbon                            capture and storage, (ii) consumer incentives for energy conservation and efficiency, and (iii) greener energy production through increased investment in clean energy technologies and incentives for the use of renewable and alternative energy sources; and |
|--------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

|   | **•** | Alberta’s *Provincial Energy Strategy*– on December 11, 2008, the Alberta government announced a long-term action plan for Alberta to achieve clean energy production, wise energy use and sustained economic prosperity. The Strategy includes actions to address the environmental footprint of                            energy and to change energy consumption behaviour by industry and consumers through conservation measures and a review of emissions targets and carbon charges for large industrial facilities, among other things. |
|--------|------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

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

 

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

 

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

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

**STATEMENT OF RESERVES DATA**

Compton’s interests in 100% of the Company’s natural gas and crude oil properties have been evaluated in a report (the “**Reserves Report**”) as of December 31, 2008, prepared by the independent international integrated petroleum engineering and geological firm, Netherland, Sewell & Associates, Inc.            (“**Netherland Sewell**”). The following summary of the Company’s reserves is calculated and reported in accordance with National Instrument 51-101, “Standards of Disclosure for Oil and Gas Activities”. Assumptions and qualifications relating to costs, prices for future production, and other matters are included below. The Reserves 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 Reserves Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables. The recovery and reserves estimates on Compton’s properties described herein are estimates only. The actual reserves on            Compton’s properties may be greater or less than those calculated and these variances may be material. Compton has no heavy oil reserves and “crude oil” refers to light and medium crude oil only.

This statement is dated March 23, 2009. The information being provided in this statement has an effective date of December 31, 2008 and a preparation date of March 19, 2009.

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

 

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**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, 2008***

 

| **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)** |
| **Proved**                     |                                                                                                                                                    |               |       |        |   |   |   |   |
| Developed producing            | 4,433                                                                                                                                                   | 3,448              | 440,375    | 371,932     | 8,087 | 5,388 | 1,928 | 1,717 |
| Developed non-producing        | 37                                                                                                                                                      | 32                 | 44,076     | 36,789      | 613 | 389 | 66 | 55 |
| Undeveloped                    | 317                                                                                                                                                     | 213                | 155,946    | 128,092     | 1,960 | 1,254 | 151 | 127 |
| **Total proved**               | 4,786                                                                                                                                                   | 3,693              | 640,396    | 536,813     | 10,660 | 7,031 | 2,145 | 1,899 |
| **Probable**                   | 3,156                                                                                                                                                   | 2,162              | 479,013    | 387,553     | 7,230 | 4,635 | 944 | 807 |
| **Total proved plus probable** | 7,942                                                                                                                                                   | 5,855              | 1,119,409  | 924,367     | 17,889 | 11,665 | 3,089 | 2,705 |
| (1)                            | Numbers may not add due to rounding.                                                                                                                    |
| (2)                            | The solution and associated gas represents 2% of the Company’s natural gas reserves and is therefore considered immaterial and is not broken out. |
|                                |                                                                                                                                                         |                    |            |             |  |  |  |  |  |

 

The tables set forth below summarize the Company’s future net revenue as of December 31, 2008, based on forecast prices and cost assumptions.

***Summary of Future Net Revenue as of December 31, 2008 (Forecast Prices)***

 

| **Reserves Category (1)**      | **Future Net Revenue ($000s)**

**Before Income Taxes Discounted at (%/year)** |
|--------------------------------|--------------------------------------------------------------------------------|
|                           | **0%**                                                                         | **5%** | **8%** | **10%** | **15%** | **20%** |
| **Proved**                     |                                                                           |   |   |   |   |   |
| Developed producing            | 3,050,340                                                                      | 1,689,491 | 1,338,834 | 1,180,781 | 922,967 | 765,922 |
| Developed non-producing        | 333,779                                                                        | 198,004 | 155,780 | 135,560 | 101,110 | 79,622 |
| Undeveloped                    | 985,397                                                                        | 528,086 | 385,902 | 318,235 | 204,504 | 135,924 |
| **Total proved**               | 4,369,516                                                                      | 2,415,580 | 1,880,515 | 1,634,575 | 1,228,581 | 981,468 |
| **Probable**                   | 2,985,501                                                                      | 1,568,642 | 1,137,095 | 934,202 | 599,571 | 402,964 |
| **Total proved plus probable** | 7,355,017                                                                      | 3,984,222 | 3,017,610 | 2,568,777 | 1,828,152 | 1,384,432 |
| (1)                            | Numbers may not add due to rounding                                            |
|                           |                                                                           |
|                                |                                                                                |  |  |  |  |  |  |

 

| **Reserves Category (1)**      | **Future Net Revenue ($000s)**

**After Income Taxes Discounted at (%/year)** |
|--------------------------------|-------------------------------------------------------------------------------|
|                           | **0%**                                                                        | **5%** | **8%** | **10%** | **15%** | **20%** |
| **Proved**                     |                                                                          |   |   |   |   |   |
| Developed producing            | 2,502,079                                                                     | 1,508,922 | 1,211,089 | 1,073,397 | 846,750 | 709,878 |
| Developed non-producing        | 272,003                                                                       | 166,708 | 132,817 | 116,529 | 88,625 | 71,103 |
| Undeveloped                    | 760,570                                                                       | 410,378 | 298,381 | 245,115 | 155,860 | 102,416 |
| **Total proved**               | 3,534,652                                                                     | 2,086,009 | 1,642,287 | 1,435,041 | 1,091,235 | 883,396 |
| **Probable**                   | 2,239,368                                                                     | 1,162,653 | 828,080 | 672,120 | 417,872 | 271,955 |
| **Total proved plus probable** | 5,774,020                                                                     | 3,248,662 | 2,470,367 | 2,107,161 | 1,509,107 | 1,155,351 |
| (1)                            | Numbers may not add due to rounding.                                          |
|                                |                                                                               |  |  |  |  |  |  |

 

 

- 23 -

 

 

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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, 2008 (Forecast Prices)***

 

| **Reserves Category(1)** | ** Revenue ($000s)**                                                                           | **Royalties ($000s)** | ** Operating Costs ($000s)** | **Develop-ment Costs ($000s)** | **Well Abandon-ment                             Costs(2) ($000s)** | **Future Net Revenue Before Income Taxes                             ($000s)** | **Income Taxes ($000s)** | **Future Net Revenue After Income Taxes ($000s)** |
|--------------------------|-----------------------------------------------------------------------------------------------------|-----------------------|-----------------------------------|--------------------------------|--------------------------------------------------------------------|--------------------------------------------------------------------------------|--------------------------|---------------------------------------------------|
| Proved                   |  9,116,304                                                                                     | 1,793,290             | 2,602,763                         | 288,745                        | 61,989                                                             | 4,369,516                                                                      | 834,864                  | 3,534,652                                         |
| Proved plus probable     | 15,732,442                                                                                          | 3,269,105             | 3,975,987                         | 1,044,656                      | 87,678                                                             | 7,355,017                                                                      | 1,580,997                | 5,774,020                                         |
| (1)                      | Numbers may not add due to rounding.                                                                |
| (2)                      | 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 group.

***Total Future Net Revenue by Production Group as of December 31, 2008 (Forecast Prices)***

 

| **Reserves Category** | **Production Group**                    | **Future Net Revenue Before Income Taxes (discounted at 10%/year) ($000s)** | **Unit Value(3) Before Income Tax (discounted at 10%/year)**

**($/bbl - $/Mcf)** |
|-----------------------|-----------------------------------------|-----------------------------------------------------------------------------|-----------------------------------------------------------------------------------|
| Proved                | Crude oil(1)                            | 166,733                                                                     | $34.84                                                                            |
|                  | Natural gas and ngls(2)                 | 1,467,843                                                                   | $2.29                                                                             |
| Proved plus probable  | Crude oil(1)                            | 247,782                                                                     | $31.20                                                                            |
|                  | Natural gas and ngls(2)                 | 2,320,995                                                                   | $2.07                                                                             |
| (1)                   | Includes solution gas and related ngls. |
| (2)                   | Excludes solution gas and related ngls. |
| (3)                   | Unit values are based on net reserves.  |
|                       |                                         |                                                                             |                                                                                   |  |

 

**Pricing Assumptions**

Future net revenue calculated using forecast prices and costs is based upon the price assumptions set out below. Netherland Sewell incorporated price forecasts which were the average of the December 31, 2008 pricing forecasts prepared by four major Canadian consulting firms in estimating Compton’s reserves data using forecast pricing and costs.

 

- 24 -

 

 

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***Summary of Forecast Pricing and Inflation Rate Assumptions as of December 31, 2008***

 

| **Year**     | **Crude Oil**                                   | **Natural Gas**                         |                            | **NGLS**               |                  | **Sulphur**              | **Inflation Rate(1)**    | **Exchange Rate** |
|--------------|-------------------------------------------------|-----------------------------------------|---------------------------------|------------------------|-----------------------|--------------------------|--------------------------|-------------------|
|         | **WTI Cushing Oklahoma ($US/bbl)**              | **Edmonton Par 40° API ($Cdn/bbl)** | **AECO C Spot****($Cdn/MMbtu)** | **Propane ($Cdn/bbl)** | **Butane ($Cdn/bbl)** | **Pentanes+ ($Cdn/bbl)** | **Plant Gate ($Cdn/lt)** | **%/Year**        | **$Cdn/$US** |
| **Forecast** |                                            |                                    |                            |                   |                  |                     |                     |              |
| 2009         | 56.56                                           | 67.24                                   | 7.20                            | 42.63                  | 51.65                 | 69.29                    | 39.20                    | 2.00%             | 0.80 |
| 2010         | 69.83                                           | 80.48                                   | 7.89                            | 50.10                  | 61.59                 | 82.90                    | 53.32                    | 2.00%             | 0.85 |
| 2011         | 78.80                                           | 87.85                                   | 8.21                            | 54.47                  | 67.24                 | 90.49                    | 56.91                    | 2.00%             | 0.85 |
| 2012         | 88.90                                           | 93.92                                   | 8.72                            | 58.33                  | 71.92                 | 96.73                    | 55.89                    | 2.00%             | 0.90 |
| 2013         | 97.42                                           | 99.81                                   | 9.24                            | 62.00                  | 76.44                 | 102.81                   | 55.71                    | 2.00%             | 0.95 |
| 2014         | 99.37                                           | 101.82                                  | 9.44                            | 63.26                  | 77.98                 | 104.87                   | 56.59                    | 2.00%             | 0.95 |
| 2015         | 101.36                                          | 103.88                                  | 9.64                            | 64.52                  | 79.57                 | 107.00                   | 57.47                    | 2.00%             | 0.95 |
| 2016         | 103.38                                          | 105.97                                  | 9.83                            | 65.81                  | 81.15                 | 109.15                   | 58.38                    | 2.00%             | 0.95 |
| 2017         | 105.43                                          | 108.06                                  | 10.04                           | 67.12                  | 82.75                 | 111.28                   | 59.31                    | 2.00%             | 0.95 |
| 2018         | 107.57                                          | 110.26                                  | 10.24                           | 68.48                  | 84.44                 | 113.57                   | 60.26                    | 2.00%             | 0.95 |
| 2019         | 109.71                                          | 112.46                                  | 10.45                           | 69.85                  | 86.13                 | 115.82                   | 61.46                    | 2.00%             | 0.95 |
| There-after  | 2.0%                                            | 2.0%                                    | 2.0%                            | 2.0%                   | 2.0%                  | 2.0%                     | 2.0%                     | 2.00%             | 0.95 |
| (1)          | Inflation rate for operating and capital costs. |
|              |                                                 |                                         |                                 |                        |                       |                          |                          |                   |  |  |  |

 

The weighted average realized sales price for Compton for the year ended December 31, 2008 was $8.17/Mcf for natural gas, $94.54/bbl for crude oil, $85.37/bbl for ngls, and $279.28/lt for sulphur.

**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.

***Reconciliation of Gross Reserves by Product Type Using Forecast Prices and Costs(1)***

 

|                           | **Crude Oil**                                                | **Ngls**                     |
|--------------------------------|--------------------------------------------------------------|------------------------------|
|                           | **Gross Proved****(Mbbl)**                                   | **Gross Probable****(Mbbl)** | **Gross Proved Plus Probable****(Mbbl)** | **Gross Proved****(Mbbl)** | **Gross Probable (Mbbl)** | **Gross Proved Plus Probable****(Mbbl)** |
| December 31, 2007         | 10,933                                                       | 6,495                        | 17,427 | 12,362 | 9,820 | 22,182 |
| Extensions                     | 125                                                          | 102                          | 228 | 511 | 285 | 796 |
| Improved recovery              | 37                                                           | (37)                         | - | 591 | (591) | - |
| Technical revisions            | (253)                                                        | (873)                        | (1,126) | (1,693) | (2,161) | (3,854) |
| Discoveries                    | 33                                                           | 7                            | 41 | 1 | 1 | 1 |
| Acquisitions                   | 1                                                            | -                            | 1 | 33 | 3 | 36 |
| Dispositions                   | (5,207)                                                      | (2,539)                      | (7,746) | (381) | (126) | (507) |
| Economic                       | -                                                            | -                            | - | - | - | - |
| Production                     | (883)                                                        | -                            | (883) | (765) | - | (765) |
| **December** **31, 2008** | **4,786**                                                    | **3,156**                    | **7,942** | **10,660** | **7,230** | **17,889** |
| (1)                            | Prepared by Management. Numbers may not add due to rounding. |
|                                |                                                              |                              |  |  |  |  |  |

 

 

- 25 -

 

 

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|                           | **Natural Gas**                                              | **Sulphur**                  |
|--------------------------------|--------------------------------------------------------------|------------------------------|
|                           | **Gross Proved****(MMcf)**                                   | **Gross Probable****(MMcf)** | **Gross Proved Plus Probable****(MMcf)** | **Gross Proved****(Mlt)** | **Gross Probable****(Mlt)** | **Gross Proved Plus Probable****(Mlt)** |
| December 31, 2007         | 744,520                                                      | 624,604                      | 1,369,124 | 2,183 | 839 | 3,022 |
| Extensions                     | 34,463                                                       | 41,418                       | 75,880 | - | - | - |
| Improved recovery              | 45,617                                                       | (45,617)                     | - | - | - | - |
| Technical revisions            | (98,203)                                                     | (123,024)                    | (221,226) | 40 | 104 | 144 |
| Discoveries                    | 23                                                           | 16                           | 39 | - | - | - |
| Acquisitions                   | 2,391                                                        | 222                          | 2,613 | - | - | - |
| Dispositions                   | (35,828)                                                     | (18,606)                     | (54,434) | - | - | - |
| Economic                       | -                                                            | -                            | - | - | - | - |
| Production                     | (52,587)                                                     | -                            | (52,587) | (78) | - | (78) |
| **December** **31, 2008** | **640,396**                                                  | **479,013**                  | **1,119,409** | **2,145** | **944** | **3,089** |
| (1)                            | Prepared by Management. Numbers may not add due to rounding. |
|                                |                                                              |                              |  |  |  |  |  |

 

|                           | **Total Reserves**                                           |
|--------------------------------|--------------------------------------------------------------|
|                           | **Gross****Proved****(Mboe)**                                | **Gross Probable****(Mboe)** | **Gross Proved Plus Probable****(Mboe)** |
| December 31, 2007         | 149,564                                                      | 121,255 | 270,819 |
| Extensions                     | 6,380                                                        | 7,291 | 13,670 |
| Improved recovery              | 8,231                                                        | (8,231) | - |
| Technical revisions            | (18,272)                                                     | (23,434) | (41,707) |
| Discoveries                    | 38                                                           | 11 | 49 |
| Acquisitions                   | 433                                                          | 40 | 473 |
| Dispositions                   | (11,559)                                                     | (5,766) | (17,325) |
| Economic                       | -                                                            | - | - |
| Production                     | (10,491)                                                     | - | (10,491) |
| **December** **31, 2008** | **124,324**                                                  | **91,164** | **215,488** |
| (1)                            | Prepared by Management. Numbers may not add due to rounding. |
|                                |                                                              |  |  |  |

 

**Additional Information Relating to Reserves Data**

**Undeveloped Reserves**

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

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

***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

 

- 26 -

 

 

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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 three year timeframe.

The following table summarizes the Company’s proved undeveloped reserves that were first attributed in each of the first three financial years and, in aggregate, before that time using forecast price and cost assumptions by production type.

 

|     | **Total Proved Undeveloped** |
|----------|------------------------------|
| **Year** | **Crude Oil****(Mbbl)**      | **Natural Gas****(MMcf)** | **Ngls****(Mbbl)** | **Sulphur****(Mlt)** |
| 2008     | 0                            | 37,687 | 624 | - |
| 2007     | 880                          | 58,996 | 713 | - |
| 2006     | 363                          | 112,627 | 774 | - |
| 2005     | 5,019                        | 84,333 | 1,731 | 118 |

 

***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 2012.

The following table summarizes the Company’s probable undeveloped reserves that were first attributed in each of the first three financial years and, in aggregate before that time using forecast price and cost assumptions by production type.

 

|     | **Total Probable Undeveloped** |
|----------|--------------------------------|
| **Year** | **Crude Oil****(Mbbl)**        | **Natural Gas****(MMcf)** | **Ngls****(Mbbl)** | **Sulphur****(Mlt)** |
| 2008     | 70                             | 37,697 | 579 | - |
| 2007     | 756                            | 139,240 | 1,322 | - |
| 2006     | 870                            | 160,174 | 1,087 | - |
| 2005     | 5,779                          | 355,237 | 5,646 | 772 |

 

**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.

 

- 27 -

 

 

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**Future Development Costs**

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

***Development Costs Deducted in Estimating Future Net Revenues(1)***

 

| **Year**                        | **Proved**                                                       | **Proved Plus Probable**                      |
|---------------------------------|------------------------------------------------------------------|-----------------------------------------------|
|                            | **Forecast Prices and****Costs/Year ($000s)**                    | **Forecast Prices and****Costs/Year ($000s)** |
| Undiscounted                    |                                                             |                                          |
| 2009                            | 19,412                                                           | 63,279                                        |
| 2010                            | 87,569                                                           | 175,249                                       |
| 2011                            | 116,974                                                          | 255,535                                       |
| 2012                            | 68,545                                                           | 298,113                                       |
| 2013                            | 396                                                              | 169,716                                       |
| Remaining                       | 57,838                                                           | 170,442                                       |
| Total undiscounted              | 350,734                                                          | 1,132,333                                     |
| Total discounted @ 10% per year | 242,635                                                          | 757,383                                       |
| (1)                             | Includes abandonment costs. Numbers may not add due to rounding. |
|                                 |                                                                  |                                               |  |

 

Based on forecast prices, Compton estimates that its internally generated cash flow will be sufficient to fund the future development costs disclosed above. Compton typically has available three sources of funding to finance its capital expenditure program: (i) internally generated cash flow from operations; (ii) debt financing when appropriate; and (iii) new equity issues, if available on favourable            terms. Compton does not expect that the costs of funding its capital expenditures will have a material effect on the economics of the programs.

**OTHER OIL AND GAS INFORMATION**

**Oil and Gas Properties and Wells**

The following table summarizes the location of the Company’s important interests as at December 31, 2008 in crude oil and natural gas wells which are producing or which the Company considers to be capable of production.

 

| **Area**         | **Producing Crude Oil Wells**                                                                                                                                                                                                                   | **Non-producing Crude Oil Wells(2)** | **Producing Natural Gas Wells** | **Non-producing Natural Gas Wells(2)** | **Total Wells** |
|------------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------|---------------------------------|----------------------------------------|-----------------|
|             | **Gross**                                                                                                                                                                                                                                       | **Net**                              | **Gross**                       | **Net**                                | **Gross**       | **Net** | **Gross** | **Net** | **Gross** | **Net** |
| **Alberta**      |                                                                                                                                                                                                                                            |                                 |                            |                                   |            |   |   |   |   |   |
| South            | 88                                                                                                                                                                                                                                              | 12.8                                 | 33                              | 20.1                                   | 1,436           | 878.3 | 400 | 183.7 | 1,957 | 1,094.9 |
| Central          | 263                                                                                                                                                                                                                                             | 103.6                                | 72                              | 16.8                                   | 527             | 185.7 | 168 | 52.7 | 1,030 | 358.8 |
| Peace River Arch | 9                                                                                                                                                                                                                                               | 2.3                                  | 1                               | 0.0                                    | 5               | 1.0 | 6 | 1.8 | 21 | 5.0 |
| **Total wells**  | **360**                                                                                                                                                                                                                                         | **118.7**                            | **106**                         | **36.9**                               | **1,968**       | **1,065.0** | **574** | **238.2** | **3,008** | **1,458.7** |
| (1)              | Numbers may not add due to rounding.                                                                                                                                                                                                            |
| (2)              | A portion of the non-producing wells are wells considered capable of production but which, for a variety of reasons including but not limited to a lack of markets and lack of development, cannot be placed on production at the present time. |
|                  |                                                                                                                                                                                                                                                 |                                      |                                 |                                        |                 |  |  |  |  |  |  |

 

 

- 28 -

 

 

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**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, 2008.

 

| **Area**     | **Gross Acres** | **Net Acres** |
|--------------|-----------------|---------------|
| Alberta      | 862,835         | 776,275       |
| Saskatchewan | 3,184           | 3,184         |
| Manitoba     | 320             | 320           |
| Montana, US  | 93,603          | 79,009        |
| **Total**    | **959,942**     | **858,788**   |

 

Compton expects that the rights to explore, develop and exploit approximately 128,650 net acres of undeveloped land may expire by December 31, 2009. There are no material work commitments associated with the company’s expiring undeveloped land holdings.

**Forward Contracts**

In 2008, Compton’s realized average field price was $58.18/boe, comprised of $8.17/Mcf for natural gas and $98.68/bbl for liquids. In 2007, Compton’s realized average field price was $44.27/boe, comprised of $6.33/Mcf for natural gas and $62.28/bbl for liquids.

Compton’s natural gas production is sold under a combination of longer term contracts with aggregators and short term daily or monthly indexed contracts. Approximately 10% of the Company’s natural gas production in 2008 was committed to aggregators. The average aggregator price realized was $1.00Mcf less than the non-aggregator prices realized during the year.

Compton’s crude oil sales are priced at Edmonton postings and are typically sold on 30 day evergreen arrangements. 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 1,500 net well sites and facilities is the sum of the calculated abandonment and reclamation liabilities adjusted for designated status as an active, inactive, abandoned, or problem site. Information regarding environmental remediation costs and other liability issues for site specific concerns were derived from a review of historical audit and assessment reports of 

 

- 29 -

 

 

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sites and facilities. An inflation rate of 2% and a credit adjusted risk free rate of 10.9% was used in the fair value calculation.

Total asset retirement costs, net of estimated salvage values, is estimated to be $124 million or $12 million when discounted at 10%. The undiscounted ARO associated with pipelines and facilities is estimated to be $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 $14 million in ARO costs            between 2009 and 2013.

**Tax Horizon**

Compton has over $1.0 billion in tax pools to apply against taxable income. Based upon planned capital expenditure programs and current commodity price assumptions, it is anticipated the Company will not be cash taxable for a significant period of time.

**Capital Expenditures**

In 2008, Compton incurred approximately $327 million of capital costs in total (excluding acquisitions and divestitures): $23 million in exploration costs and $303 million in development costs. In addition, approximately $128 million was received on net proved property dispositions and $64 million was received on net unproved property dispositions.

**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, 2008 and 2007.

 

|              | **Year Ended December 31, 2008** |            | **Year Ended December 31, 2007** |
|-------------------|----------------------------------|-----------------|----------------------------------|
|              | **Development**                  | **Exploratory** |                             | **Development** | **Exploratory** |
|              | **Gross**                        | **Net**         | **Gross**                        | **Net** |   | **Gross** | **Net** | **Gross** | **Net** |
| Natural gas       | 229                              | 175             | 3                                | 2 |   | 257 | 219 | 19 | 15 |
| Crude oil         | 8                                | 2               | 1                                | 1 |   | 24 | 13 | 1 | 1 |
| Dry and abandoned | 9                                | 6               | 1                                | 1 |   | 4 | 4 | 6 | 5 |
| **Total**         | 246                              | 183             | 5                                | 4 |   | 285 | 236 | 26 | 21 |
| **Success Ratio** | 96%                              |            | 97%                              |

 

In 2009, the Company expects to continue to focus its resources in Alberta, Canada. Compton’s overall objective for 2009 is to focus primarily on development activities and the advancement of reserves from the proved undeveloped and probable categories to the proved producing classification. The Company is currently revisiting its 2009 plans in light of the continued decline in commodity prices            and its commitment to limit capital spending to funds generated from operations.

 

- 30 -

 

 

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**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***(1)

 

| **Product Type**               | **Fiscal 2008 Three Months Ended**   | **Year Ended**       |
|--------------------------------|--------------------------------------|----------------------|
|                           | **March 31, 2008**                   | **June 30,****2008** | **September 30, 2008** | **December 31, 2008** | **December 31, 2008** |
| Natural gas (MMcf/d)           | 170                                  | 150                  | 130 | 125 | 143 |
| Natural gas (MMcf)             | 15,433                               | 13,603               | 11,969 | 11,457 | 52,462 |
|                           |                                 |                 |   |   |   |
| Natural gas liquids (boe/d)(2) | 2,335                                | 2,574                | 2,066 | 2,543 | 2,379 |
| Natural gas liquids (Mboe)(2)  | 212                                  | 234                  | 190 | 234 | 871 |
|                           |                                 |                 |   |   |   |
| Crude oil (bbl/d)              | 2,674                                | 3,069                | 2,257 | 1,570 | 2,390 |
| Crude oil (Mbbls)              | 243                                  | 279                  | 208 | 144 | 875 |
|                           |                                 |                 |   |   |   |
| Total liquids (boe/d)          | 5,009                                | 5,643                | 4,323 | 4,113 | 4,769 |
| Total liquids (Mboe)           | 455                                  | 513                  | 398 | 378 | 1,746 |
|                           |                                 |                 |   |   |   |
| Total (boe/d)                  | 33,274                               | 30,557               | 26,006 | 24,868 | 28,658 |
| Total (Mboe)                   | 3,028                                | 2,781                | 2,393 | 2,288 | 10,489 |
| (1)                            | Numbers may not add due to rounding. |
| (2)                            | Includes sulphur.                    |
|                                |                                      |                      |  |  |  |  |

 

 

| **Product Type**               | **Fiscal 2007 Three Months Ended**   | **Year Ended**       |
|--------------------------------|--------------------------------------|----------------------|
|                           | **March 31, 2007**                   | **June 30,****2007** | **September** **30, 2007** | **December 31, 2007** | **December 31, 2007** |
| Natural gas (MMcf/d)           | 148                                  | 130                  | 135 | 167 | 145 |
| Natural gas (MMcf)             | 13,277                               | 11,859               | 12,413 | 15,361 | 52,910 |
|                           |                                 |                 |   |   |   |
| Natural gas liquids (boe/d)(2) | 2,705                                | 1,714                | 2,231 | 2,239 | 2,221 |
| Natural gas liquids (Mboe)(2)  | 243                                  | 156                  | 205 | 206 | 810 |
|                           |                                 |                 |   |   |   |
| Crude oil (bbl/d)              | 6,024                                | 5,485                | 5,723 | 2,579 | 4,945 |
| Crude oil (Mbbls)              | 542                                  | 499                  | 526 | 237 | 1,805 |
|                           |                                 |                 |   |   |   |
| Total liquids (boe/d)          | 8,729                                | 7,199                | 7,954 | 4,818 | 7,166 |
| Total liquids (Mboe)           | 785                                  | 655                  | 731 | 443 | 2,615 |
|                           |                                 |                 |   |   |   |
| Total (boe/d)                  | 33,316                               | 28,918               | 30,440 | 32,646 | 31,326 |
| Total (Mboe)                   | 2,998                                | 2,632                | 2,800 | 3,003 | 11,434 |
| (1)                            | Numbers may not add due to rounding. |
| (2)                            | Includes sulphur.                    |
|                                |                                      |                      |  |  |  |  |

 

 

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**2009 Production Estimates**

Production volumes in 2009, as estimated in the Company’s reserve forecast from Netherland Sewell before deduction of royalties, are set forth below.

 

| **Reserves Category(1)**       | **Crude Oil(bbl/d)**                                                                                                                   | **Natural Gas****(MMcf/d)** | **Ngls****(bbl/d)** | **Sulphur****(lt/d)** | **Total****(boe/d)** |
|--------------------------------|----------------------------------------------------------------------------------------------------------------------------------------|-----------------------------|---------------------|-----------------------|----------------------|
| **Proved**                     |                                                                                                                                   |                        |                |                  |                 |
| Developed producing            | 1,209                                                                                                                                  | 104                         | 1,850               | 203                   | 20,550               |
| Developed non-producing        | 13                                                                                                                                     | 7                           | 83                  | 1                     | 1,183                |
| Undeveloped                    | -                                                                                                                                      | 1                           | 19                  | -                     | 127                  |
| **Total proved**               | 1,222                                                                                                                                  | 111                         | 1,952               | 204                   | 21,860               |
| **Probable**                   | 240                                                                                                                                    | 10                          | 244                 | 6                     | 2,078                |
| **Total proved plus probable** | 1,462                                                                                                                                  | 120                         | 2,195               | 210                   | 23,938               |
| (1)                            | Numbers may not add due to rounding. Based on estimates only. Variances may occur due to circumstances beyond Compton’s control. |
|                                |                                                                                                                                        |                             |                     |                       |                      |  |

 

 

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

 

|                               | **Fiscal 2008 Three Months Ended**                                                                                                                                                                                                                                                                                       | **Year Ended**                |
|------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------------|
|                               | **March** **31, 2008**                                                                                                                                                                                                                                                                                              | **June** **30,****2008** | **September** **30, 2008** | **December** **31, 2008** | **December** **31, 2008** |
| **Natural gas ($/Mcf)**            |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $ 7.48                                                                                                                                                                                                                                                                                                                   | $ 9.42                        | $ 8.75 | $ 6.99 | $ 8.17 |
| Royalties                          | (1.60)                                                                                                                                                                                                                                                                                                                   | (1.83)                        | (1.75) | (1.14) | (1.59) |
| Operating costs(1)                 | (1.53)                                                                                                                                                                                                                                                                                                                   | (1.71)                        | (1.88) | (2.08) | (1.78) |
| Transportation costs               | (0.11)                                                                                                                                                                                                                                                                                                                   | (0.11)                        | (0.11) | (0.11) | (0.11) |
| Netback                            | $ 4.24                                                                                                                                                                                                                                                                                                                   | $ 5.77                        | $ 5.01 | $ 3.66 | $ 4.69 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Natural gas liquids ($/bbl)(3)** |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $ 97.63                                                                                                                                                                                                                                                                                                                  | $ 116.30                      | $ 139.88 | $ 63.97 | $ 102.83 |
| Royalties                          | (23.37)                                                                                                                                                                                                                                                                                                                  | (30.93)                       | (34.42) | (12.01) | (24.76) |
| Operating costs(1)                 | (9.18)                                                                                                                                                                                                                                                                                                                   | (10.28)                       | (11.27) | (12.46) | (10.66) |
| Transportation costs               | (1.22)                                                                                                                                                                                                                                                                                                                   | (2.10)                        | (2.05) | (0.42) | (1.42) |
| Netback                            | $ 63.86                                                                                                                                                                                                                                                                                                                  | $ 72.99                       | $ 92.14 | $ 39.08 | $ 65.99 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Crude oil ($/bbl)**              |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $ 92.64                                                                                                                                                                                                                                                                                                                  | $ 105.41                      | $ 109.56 | $ 55.13 | $ 94.54 |
| Royalties                          | (15.54)                                                                                                                                                                                                                                                                                                                  | (19.94)                       | (20.45) | (8.19) | (16.90) |
| Operating costs(1)                 | (13.43)                                                                                                                                                                                                                                                                                                                  | (9.82)                        | (13.61) | (16.23) | (12.94) |
| Transportation costs               | (1.22)                                                                                                                                                                                                                                                                                                                   | (2.10)                        | (2.05) | (0.42) | (1.57) |
| Netback                            | $ 62.45                                                                                                                                                                                                                                                                                                                  | $ 73.55                       | $ 73.45 | $ 30.29 | $ 63.13 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Total liquids ($/bbl)**          |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $ 94.97                                                                                                                                                                                                                                                                                                                  | $ 110.37                      | $ 124.05 | $ 60.60 | $ 98.68 |
| Royalties                          | (19.19)                                                                                                                                                                                                                                                                                                                  | (24.96)                       | (27.13) | (10.55) | (20.82) |
| Operating costs(1)                 | (11.45)                                                                                                                                                                                                                                                                                                                  | (10.03)                       | (12.49) | (13.90) | (11.80) |
| Transportation costs               | (1.22)                                                                                                                                                                                                                                                                                                                   | (2.10)                        | (2.05) | (0.42) | (1.49) |
| Netback                            | $ 63.11                                                                                                                                                                                                                                                                                                                  | $ 73.28                       | $ 82.38 | $ 35.73 | $64.57 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Total ($/boe)**                  |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price(2)                           | $ 53.07                                                                                                                                                                                                                                                                                                                  | $ 67.20                       | $ 66.03 | $ 45.79 | $ 58.18 |
| Royalties                          | (11.06)                                                                                                                                                                                                                                                                                                                  | (13.55)                       | (13.25) | (7.46) | (11.43) |
| Operating costs(1)                 | (9.53)                                                                                                                                                                                                                                                                                                                   | (10.23)                       | (11.47) | (12.70) | (10.85) |
| Transportation costs               | (0.74)                                                                                                                                                                                                                                                                                                                   | (0.93)                        | (0.89) | (0.62) | (0.80) |
| Netback                            | $ 31.74                                                                                                                                                                                                                                                                                                                  | $ 42.49                       | $ 40.42 | $  25.01 | $ 35.10 |
| (1)                                | A portion of our natural gas production is associated with our crude oil production; additionally the production of natural gas liquids is associated with our natural gas production. As a result, per unit operating costs for each product line reflect the allocation of certain common costs in this determination. |
| (2)                                | Includes third party processing fees, but not includedin product pricing.                                                                                                                                                                                                                                                |
| (3)                                | Includes sulphur.                                                                                                                                                                                                                                                                                                        |
|                                    |                                                                                                                                                                                                                                                                                                                          |                               |  |  |  |  |

 

 

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|                               | **Fiscal 2007 Three Months Ended**                                                                                                                                                                                                                                                                                       | **Year Ended**                |
|------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|-------------------------------|
|                               | **March** **31, 2007**                                                                                                                                                                                                                                                                                              | **June** **30,****2007** | **September** **30, 2007** | **December** **31, 2007** | **December** **31, 2007** |
| **Natural gas ($/Mcf)**            |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $7.24                                                                                                                                                                                                                                                                                                                    | $6.92                         | $5.23 | $6.00 | $6.33 |
| Royalties                          | (1.52)                                                                                                                                                                                                                                                                                                                   | (1.35)                        | (1.26) | (1.32) | (1.36) |
| Operating costs(1)                 | (1.30)                                                                                                                                                                                                                                                                                                                   | (1.34)                        | (1.22) | (1.44) | (1.33) |
| Transportation costs               | (0.11)                                                                                                                                                                                                                                                                                                                   | (0.11)                        | (0.11) | (0.11) | (0.11) |
| Netback                            | $4.31                                                                                                                                                                                                                                                                                                                    | $4.12                         | $2.64 | $3.13 | $3.53 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Natural gas liquids ($/bbl)(3)** |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $49.49                                                                                                                                                                                                                                                                                                                   | $52.23                        | $51.21 | $79.40 | $58.05 |
| Royalties                          | (12.61)                                                                                                                                                                                                                                                                                                                  | (12.10)                       | (12.32) | (16.34) | (13.39) |
| Operating costs(1)                 | (7.79)                                                                                                                                                                                                                                                                                                                   | (8.01)                        | (7.32) | (8.61) | (7.97) |
| Transportation costs               | (2.57)                                                                                                                                                                                                                                                                                                                   | (2.67)                        | (2.54) | (2.63) | (2.60) |
| Netback                            | $26.52                                                                                                                                                                                                                                                                                                                   | $29.45                        | $29.03 | $51.82 | $34.09 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Crude oil ($/bbl)**              |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $58.13                                                                                                                                                                                                                                                                                                                   | $63.08                        | $66.09 | $76.04 | $64.17 |
| Royalties                          | (9.91)                                                                                                                                                                                                                                                                                                                   | (10.76)                       | (11.27) | (12.80) | (10.92) |
| Operating costs(1)                 | (12.74)                                                                                                                                                                                                                                                                                                                  | (12.79)                       | (14.78) | (15.70) | (13.72) |
| Transportation costs               | (2.57)                                                                                                                                                                                                                                                                                                                   | (2.67)                        | (2.54) | (2.63) | (2.60) |
| Netback                            | $32.91                                                                                                                                                                                                                                                                                                                   | $36.86                        | $37.50 | $44.91 | $36.93 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Total liquids ($/bbl)**          |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price                              | $55.45                                                                                                                                                                                                                                                                                                                   | $60.49                        | $61.91 | $77.60 | $62.28 |
| Royalties                          | (10.75)                                                                                                                                                                                                                                                                                                                  | (11.08)                       | (11.56) | (14.44) | (11.68) |
| Operating costs(1)                 | (11.21)                                                                                                                                                                                                                                                                                                                  | (11.65)                       | (12.69) | (12.41) | (11.94) |
| Transportation costs               | (2.57)                                                                                                                                                                                                                                                                                                                   | (2.67)                        | (2.54) | (2.63) | (2.60) |
| Netback                            | $30.92                                                                                                                                                                                                                                                                                                                   | $35.09                        | $35.12 | $48.12 | $36.06 |
|                               |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| **Total ($/boe)**                  |                                                                                                                                                                                                                                                                                                                     |                          |   |   |   |
| Price(2)                           | $47.57                                                                                                                                                                                                                                                                                                                   | $46.93                        | $39.85 | $42.77 | $44.27 |
| Royalties                          | (9.55)                                                                                                                                                                                                                                                                                                                   | (8.86)                        | (8.61) | (8.86) | (8.98) |
| Operating costs(1)                 | (8.68)                                                                                                                                                                                                                                                                                                                   | (8.92)                        | (8.72) | (9.17) | (8.88) |
| Transportation costs               | (1.16)                                                                                                                                                                                                                                                                                                                   | (1.16)                        | (1.15) | (0.95) | (1.10) |
| Netback                            | $28.18                                                                                                                                                                                                                                                                                                                   | $27.99                        | $21.37 | $23.79 | $25.31 |
| (1)                                | A portion of our natural gas production is associated with our crude oil production; additionally the production of natural gas liquids is associated with our natural gas production. As a result, per unit operating costs for each product line reflect the allocation of certain common costs in this determination. |
| (2)                                | Includes third party processing fees, but not includedin product pricing.                                                                                                                                                                                                                                                |
| (3)                                | Includes sulphur.                                                                                                                                                                                                                                                                                                        |
| (4)                                | Certain amounts have been reclassified to conform with current period presentation.                                                                                                                                                                                                                                      |
|                                    |                                                                                                                                                                                                                                                                                                                          |                               |  |  |  |  |

 

 

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The following table indicates average daily gross production from important areas in respect of Compton’s assets for the year ended December 31, 2008:

 

| **Area**         | **Crude Oil****(Bbls/d)** | **Natural Gas****(Mcf/d)** | **Ngls****(Bbls/d)** | **Total****(Boe/d)** |
|------------------|---------------------------|----------------------------|----------------------|----------------------|
|             |                      |                       |                 |                 |
| Southern Alberta | 426                       | 84,383                     | 1,164                | 15,654               |
| Central Alberta  | 1,086                     | 45,741                     | 1,105                | 9,815                |
| Peace River Arch | 848                       | 11,713                     | 87                   | 2,887                |
| Other            | 30                        | 1,502                      | 23                   | 302                  |
| **Total**        | 2,390                     | 143,339                    | 2,379                | 28,658               |

 

**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 125,573,451 common shares are issued and outstanding as fully paid and non-assessable shares as at March 23, 2009. No preferred shares are issued and outstanding as at March 23, 2009. The following is a description of Company’s common and preferred            shares.

**Common Shares**

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

**Preferred Shares**

The preferred shares may be issued in one or more series, and the directors are authorized to fix the number of shares in each series and to determine the designation, rights, privileges, restrictions, and conditions attached to the shares of each series. Holders of preferred shares do not hold voting rights. The preferred shares are entitled to a priority over the common shares with respect to the            payment of dividends and the distribution of assets upon the liquidation, dissolution, or winding-up of Compton.

 

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**Shareholder Rights Plan**

As Compton’s current shareholder rights plan expires on June 3, 2009, the shareholders will be asked at the annual and special meeting of Compton shareholders to be held on May 11, 2009 (the “**Meeting**”) to consider and, if deemed advisable, to approve a resolution to ratify the adoption of a new shareholder rights plan (the            “**Shareholder Rights Plan**”). The Shareholder Rights Plan, unanimously adopted by the Board, is contained in an agreement that will be entered into with Computershare Trust Company of Canada effective as of June 3, 2009. The Shareholder Rights Plan is substantially the same as Compton’s current shareholder rights plan which was ratified by the shareholders in 2003 and reconfirmed in 2006. The Shareholder Rights Plan            will become effective as of June 3, 2009 and will continue in effect unless the shareholders do not approve the Shareholder Rights Plan resolution. In order to be effective, the Shareholder Rights Plan resolution must be approved by a majority of the votes cast at the Meeting by shareholders present in person or represented by proxy. The Shareholder Rights Plan is subject to acceptance by the Toronto Stock Exchange (the            “**TSX**”). Shareholders may, on or about March 31, 2009, obtain a copy of the Shareholder Rights Plan on **www.sedar.com**or from the Corporate Secretary of the Corporation at (403) 237-9400 or by writing to Compton Petroleum Corporation, Suite 3400, 425 – 1st Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada, T2P 3L8, Attention: Corporate            Secretary.

**MARKET FOR SECURITIES**

The outstanding common shares of the Company are listed on the 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.

 

| **Period**                         | **TSX High Close** | **TSX Low Close** | **TSX Average Daily Trading Volume** |
|------------------------------------|--------------------|-------------------|--------------------------------------|
| **2008**                           |               |              |                                 |
|     January         | $9.79              | $8.79             | 409,255                              |
|     February        | $11.80             | $9.75             | 536,633                              |
|     March           | $12.05             | $11.03            | 425,224                              |
|     April           | $12.30             | $11.20            | 447,155                              |
|     May             | $12.30             | $11.20            | 453,852                              |
|     June            | $13.20             | $11.41            | 403,721                              |
|     July            | $12.90             | $10.51            | 354,473                              |
|     August          | $10.31             | $8.40             | 454,594                              |
|     September       | $8.54              | $5.45             | 449,800                              |
|     October         | $5.40              | $2.30             | 544,669                              |
|     November        | $2.43              | $0.94             | 833,115                              |
|     December        | $1.23              | $0.88             | 1,016,721                            |
|                               |               |              |                                 |
| **2009**                           |               |              |                                 |
|     January    | $1.33              | $0.98             | 481,889                              |
|     February        | $1.02              | $0.56             | 648,237                              |
|     March 1-20 | $0.88              | $0.58             | 452,276                              |

 

 

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**CONFLICTS OF INTEREST**

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

**INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS**

None of the current executive officers or directors of Compton, and no person or company that is the direct or indirect beneficial owner of, or who exercised control or direction over more than 10% of the common shares of Compton, nor any associate or affiliate of the foregoing has or has had, at any time, any material interest, directly or indirectly, in any transaction or proposed transaction that            has materially affected or would materially affect Compton.

**CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS**

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

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

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

 

- 37 -

 

 

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**MATERIAL CONTRACTS**

Except for contracts entered into in the ordinary course of business, Compton has not entered into any material contracts within the last financial year, or before the last financial year which are still in effect, other than as follows: an Indenture dated as of November 22, 2005, among Compton Petroleum Finance Corporation, Compton, as parent guarantor, Hornet Energy Ltd., Compton Petroleum            (partnership) and Compton Petroleum Holdings Corporation, as the initial subsidiary guarantors, and The Bank of Nova Scotia Trust Company of New York, as trustee, whereby, on November 22, 2005, Compton Petroleum Finance Corporation issued and sold U.S.$300 million aggregate principal amount of senior term notes, which are unsecured and bear interest semi-annually, in arrears on December 1 and June 1 of each year, at a rate of  7 5/8% per year, with principal            repayable on December 1, 2013. On April 4, 2006, Compton Petroleum Finance Corporation issued an additional U.S.$150 million aggregate principal amount of senior term notes under this Indenture on the same terms and conditions as the senior terms notes issued on November 22, 2005. The senior notes are guaranteed by Compton and the initial subsidiary guarantors.

Compton’s bank debt is composed of a syndicated, extendable, revolving credit facility with a current authorized limit of $500 million. This facility was renewed on July 2, 2008 under substantially identical terms and conditions except that certain syndicate members, representing $90 million of the authorized amount of $500 million, elected not to extend their participation beyond July 2, 2009.            The next scheduled annual review of the facility will occur in late spring 2009; if not extended at that time, amounts then outstanding under the facility are due July 3, 2010. Additionally, should the four remaining syndicate members, three of which are Canadian chartered banks, not increase their participation or new syndicate participants not be secured, the authorized amount would be reduced to $410 million or such other amount as the syndicate determines. The facility is a            borrowing-based facility with the borrowing base being determined by the syndicate based primarily on year-end reserves and giving effect to the banks’ commodity price assumptions. As at December 31, 2008 the company had drawn $290 million on the facility.

The amount that may be drawn on the syndicated facility is limited by a provision contained in the Trust Indenture related to the company’s senior notes. The provision limits secured debt to an amount not to exceed an Adjusted Consolidated Net Tangible Asset Value (“**ACNTA**”), as defined in the Indenture. The ACTNA calculation is made            quarterly and is based upon year-end reserves utilizing December 31, 2008 constant dollar prices. A preliminary ACNTA calculation at December 31, 2008 indicates that drawings on the company’s secured debt may be limited to approximately $375 million as a result of this provision.

**LEGAL PROCEEDINGS AND REGULATORY ACTIONS**

To the knowledge of the Company, there are no legal proceedings material to the Company to which the Company is or was a party to or of which any of its properties is or was the subject of, during the financial year ended December 31, 2008 nor are there any such proceedings known to the Company to be contemplated.

During the year ended December 31, 2008, there were no: (i) penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority; (ii) penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decision, or (iii)            settlement agreements the Company entered into before a court relating to securities legislation or with a securities regulatory authority.

 

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**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, the independent reserve auditors of Compton, personally disclosed in certificates of qualification that they neither held, 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 Petroleum Finance Corporation’s U.S. $450 million 7 5/8% Senior Notes as B- and B3 respectively, as at December 31, 2008. 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 non-payment, 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 B3 are considered speculative and are subject to high credit risk.

**DIRECTORS AND OFFICERS**

**Directors**

Mr. Sapieha has resigned from the Board effective February 28, 2009. 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, however, John Preston, a director since 1993, has elected to not stand for re-election at this year’s Meeting. Mr. John Thomson, having previously            notified the Company of his intention to not stand for re-election to the Board of Directors and having fulfilled all of his duties with respect to the 2008 year-end statutory reporting as Chair of the Audit, Finance and Risk Committee, submitted his resignation effective March 23, 2009.

The next Meeting is scheduled for May 11, 2009 at 3:30 p.m. (Calgary time) in the Historical Ballroom on the Fourth Floor of the Calgary Chamber of Commerce, 517 Centre Street South, Calgary, Alberta, Canada.

 

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The Board of Directors has established an Audit, Finance and Risk Committee; an Engineering, Operations and Reserves Committee; a Human Resources, Compensation, Environmental, Health and Safety Committee; and a Corporate Governance Committee. All independent directors, other than Peter Seldin, sit on each of the Board Committees. Mr. Granger does not sit on the Board Committees since he is            a non-independent director due to his position as President & Chief Executive Officer.

The name, city of residence, and principal occupation during the last five years of each of the current directors of the Company (other than Mr. Preston) are set forth in the following table.

 

| **Name and Municipality of Residence**                          | **Principal Occupation**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                | **Director Since** |
|-----------------------------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------|
| Mel F. Belich, Q.C.Calgary, AB, Canada                          | Chairman, Compton Petroleum Corporation. Mr. Belich has been Chairman and President of each of Enbridge International Inc. and Enbridge Technology Inc., and a director of numerous affiliates of Enbridge Inc., a pipeline company, including those in Europe and Latin America.

Mr. Belich is the Chairman of the Board of Directors of Compton and the Chairman of the Corporate Governance Committee.                                                                                                                                                                                    | 1993               |
| J. Stephens Allan,F.C.A., ICD.D

Calgary, AB, Canada            | Consultant to RSM Richter LLP, one of the largest independent accounting, business advisory, and consulting firms in Canada. Mr. Allan has 38 years of experience as a Chartered Accountant, which includes extensive experience in corporate restructuring and complex corporate litigation matters. He was awarded an FCA in 1992. He is currently the                            Chairman, Canadian Tourism Commission and Chairman of the Independent Review Committee, Citadel Group of Funds.                                                                                                | 2007               |
| David Fitzpatrick, P.Eng., C. Dir.

Calgary, AB, Canada

  | Independent businessman and prior thereto was the President, CEO and Director of Shiningbank Energy Ltd. from 1996 to 2007 (acquired by PrimeWest Energy). Mr. Fitzpatrick has served as a Director of PrimeWest Energy, Shiningbank Energy Income Fund, Platform Energy and Twin Butte Energy Ltd., each of which is or was an oil and gas company or                            trust.                                                                                                                                                                                                                | 2009               |
| Tim Granger, P. Eng.Calgary, AB, Canada                         | President & Chief Executive Officer of the Company effective January 26, 2009. Mr. Granger previously served as Vice President, and Chief Operating Officer at Paramount Energy Trust, a natural gas royalty energy trust, and prior to that Mr. Granger was Managing Director of TAQA North, an oil and gas exploration company, following the                            acquisition of Primewest Energy Trust by TAQA in January of 2008. Prior to such acquisition Mr. Granger had served as the Chief Operating Officer of Primewest, an oil and gas royalty trust, since 1999. | 2009               |
| Brad Hurtubise, B. Comm, MBA, CFA

Calgary, AB, Canada

   | President, Chief Executive Officer, and a Director of Eaglewood Energy Inc., an international oil and gas company. Previously, he held the roles of Executive Managing Director, Investment Banking at Tristone Capital Inc. During his career, Mr. Hurtubise held senior leadership positions in several petroleum and financial sector companies. Mr.                            Hurtubise is also on the Boards of Ithaca Energy Inc., DirectCash Income Fund, the Alberta Children’s Hospital Foundation, and also serves on the Advisory Board of Marsh Canada.                              | 2009               |

 

 

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| **Name and Municipality of Residence**            | **Principal Occupation**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        | **Director Since** |
|---------------------------------------------------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------|
| Irvine J. Koop, P. Eng.Calgary, AB, Canada        | Independent businessman and prior thereto was the Chairman and Chief Executive Officer of IKO Resources Inc., a petroleum consulting firm. Mr. Koop was the President and CEO, Pipelines and Midstream of Westcoast Energy Inc., an energy products and services company (acquired by Duke Energy Company), and was the former president and CEO of Numac                            Energy, an oil and gas company (acquired by Anderson Exploration). Mr. Koop is also a Director of NAL Energy, a public oil and gas trust.

Mr. Koop is the Chairman of the Human Resources, Compensation, Environmental, Health and Safety Committee. | 1996               |
| Peter K. SeldinNew York, New York, United States  | Founder and Managing Member of Centennial Energy Partners, L.L.C., general partner of four energy–sector investment partnerships that invest in oil and gas producers and oilfield service companies worldwide. Mr. Seldin is also a director of Tesco Corporation, an oilfield equipment and services company.                                                                                                                                                                                                                                                                                                                      | 2008               |
| Warren ShimmerlikBedford, New York, United States | Independent businessman and currently a consultant to Centennial Energy Partners, L.L.C., a major shareholder of the Company. Previously, he was a Principal of COSCO Capital Management LLC, a private equity intermediary. He spent nearly two decades as a highly regarded Wall Street investment analyst, holding senior positions at Merrill Lynch &                            Company, L. F. Rothschild Unterberg Towbin and County NatWest Securities USA.                                                                                                                                                                          | 2009               |
| Jeffrey T. Smith, P. Geol.Calgary, AB, Canada     | Independent Businessman and prior thereto, Chief Operating Officer of Northstar Energy Corporation, an oil and gas company (acquired by Devon Energy). He is also a Director of Provident Energy and Chairman of Intrepid Energy Corp., a private exploration and production company.

Mr. Smith is Chairman of the Engineering, Reserves and Operations Committee.                                                                                                                                                                                                                                                                        | 1999               |

 

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 23, 2009 relating to the Meeting to be held on May 11, 2009, which sections are incorporated by reference into this AIF.

 

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**Officers**

Information is given below with respect to each of the current officers of the Company. 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.

 

| **Name and Municipality of Residence**      | **Principal Occupation**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           |
|---------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Tim Granger, P. Eng.Calgary, Alberta        | President & Chief Executive Officer of the Company effective January 26, 2009. Mr. Granger previously served as Vice President, Asset Optimization and Chief Operating Officer at Paramount Energy Trust, a natural gas royalty energy trust, and prior to that Mr. Granger was Managing Director TAQA North, an oil and gas exploration                            company, following the acquisition of Primewest Energy Trust by TAQA in January of 2008. Prior to such acquisition Mr. Granger had served as the Chief Operating Officer of Primewest, an oil and gas royalty trust, since 1999. |
| Gary Follensbee, P. Eng.

Calgary, Alberta  | Vice President, Engineering & Exploitation of the Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |
| Marc R. Junghans, P. Geol.Calgary, Alberta  | Vice President, Exploration of the Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| Norman G. Knecht, C.A.Calgary, Alberta      | Vice President, Finance & Chief Financial Officer of the Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              |
| Tim G. Millar, LL.B.Calgary, Alberta        | Vice President, General Counsel & Corporate Secretary of the Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |
| Murray J. Stodalka, P. Eng.Calgary, Alberta | Vice President, Operations of the Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |

 

As at March 23, 2009 the directors and officers of Compton as a group beneficially owned or controlled, directly or indirectly, 6,925,796 common shares of Compton, representing approximately 5.5% 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.

Mr. Seldin, a Director, is the founder and managing member of Centennial Energy Partners, L.L.C., which itself and through Centennial Energy Partners, L.P., Centennial Energy Partners V, L.P., Quadrennial Partners L.P., and Hoyt Farm Partners L.P., owns 25,545,796 Common Shares, representing approximately 20.3% of the outstanding Common Shares. Management has been advised by Mr. Seldin that he does            not, directly or indirectly, own, control or hold any Common Shares.

 

**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: J. Stephens Allan (appointed as of March 23, 2009); John A. Thomson (prior to his resignation as of March 23, 2009)

Members: J. Stephens Allan, Mel F. Belich, Irvine J. Koop, John W. Preston, Jeffrey T. Smith

 

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Based upon applicable Canadian and United States securities laws and the New York Stock Exchange corporate governance rules, Compton has adopted “Standards of Independence,” which may be viewed in full on the Company’s website. The Board affirmatively determines on an annual basis the independence of its members. Messrs. Allan, Belich, Koop, Preston, Smith, and Thomson have been            determined to be independent directors.

Mr. Thomson is considered to be a “financial expert,” as defined in National Instrument 52-110, “Audit Committees,” (“**NI 52-110**”) issued by the CSA, due to his experience in the oil and natural gas industry as a Chartered Accountant, as Chief Financial Officer of a major public oil and natural gas company, and            as a board member and Officer for other public reporting oil and natural gas companies. All other Committee members are “financially literate,” as defined in NI 52-110, due to their experience in various management positions or qualification as a Chartered Accountant.

Mr. Thomson has resigned from the Board effective March 23, 2009. The Board of Directors will designate a new financial expert in due course.

**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, 2008 and 2007 were as follows:

 

| **Type of Service**       | **Fiscal 2008**                                                                                      | **Fiscal 2007(1)**                                                               |
|---------------------------|------------------------------------------------------------------------------------------------------|----------------------------------------------------------------------------------|
| Financial statement audit | $500,920                                                                                             | $639,250                                                                         |
| Internal controls audit   |   360,054                                                                                       |    547,400                                                             |
| Audit related             |     55,765                                                                            |      48,200                                             |
| Tax                       |              -                      |               - |
| Other non-audit           |        1,220                                                           |       48,000                                            |
| Total                     | $917,959                                                                                             | $1,282,850                                                                       |
| (1)                       | 2007 amounts have been updated to account for differences between accrued costs and actual billings. |
|                           |                                                                                                      |                                                                                  |  |

 

Financial statement audit fees in fiscal 2008 and 2007 include those charged in respect of the annual financial statement audit as well as those charged for the quarterly review of the financial statements.

Fees charged in 2008 and 2007 for the audit of internal controls relate to requirements under the United States Sarbanes-Oxley Act of 2002 and similar Canadian regulatory compliance.

Audit related fees include services performed to translate the annual and quarterly financial statements into French as well as the reimbursement of the pro-rata share of annual fees changed to each audit firm by the Canadian Public Accountability Board.

There were no tax services performed by Grant Thornton outside of normal audit procedures during 2008 and 2007. Other non-audit fees relate to minor GST research completed in 2008 and in 2007 the audit of certain oil and gas properties prior to disposition.

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 

 

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non-audit related services would be provided to the Company by Grant Thornton LLP and in such case, only with the prior approval of the Audit, Finance and Risk Committee. The Committee has pre-approved Management to retain Grant Thornton LLP to provide miscellaneous, minor, non-audit services in circumstances where it is not feasible or practical to convene a meeting of the Audit, Finance and Risk            Committee, subject to an aggregate limit of $25,000 per quarter.

**TRANSFER AGENT AND REGISTRAR**

The transfer agent and registrar for the Company’s shares is Computershare Trust Company of Canada at its office: 600, 530 – 8th Avenue, Calgary, Alberta, T2P 3S8.

**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 23, 2009, relating to the Annual and Special Meeting of Shareholders to be held            on May 11, 2009. Additional financial information is also provided in the consolidated financial statements and Management’s Discussion and Analysis of the Company for the year ended December 31, 2008, included in the Company’s 2008 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 AIF are available to the public and may be obtained by contacting:

 

|   | Compton Petroleum Corporation           |
|--------|-----------------------------------------|
|   | Suite 3400, 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 |

 

 

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**SCHEDULE A****REPORT ON RESERVES DATA BY INDEPENDENT****QUALIFIED RESERVES EVALUATOR OR AUDITOR**

 

**FORM 51-101F2**

**REPORT ON RESERVES DATA BY INDEPENDENT**

**QUALIFIED RESERVES EVALUATOR OR AUDITOR**

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

 

|   | 1.     | We have evaluated the Company's reserves data as at December 31, 2008. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.                                                                                                                                                                                                                                                     |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|   | 2.     | The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.                                                                                                                                                                                                                                                                                                                                        |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|   |   | We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|   | 3.     | Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.                                                                                                                                                                                     |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |
|   | 4.     | The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2008, and identifies                            the respective portions thereof that we have evaluated and reported on to the Company's board of directors: |

 

| Independent Qualified                     |   | Description and Preparation Date of |   | Location of Reserves (Country or Foreign |   | Net Present Value of Future Net Revenue(before Canadian federal income taxes, 10% discount rate) (MC$) |
|-------------------------------------------|--------|-------------------------------------|--------|------------------------------------------|--------|--------------------------------------------------------------------------------------------------------|
| Reserves Evaluator                        |   | Evaluation Report                   |   | Geographic Area)                         |   | Audited                                                                                                |   | Evaluated |   | Reviewed |   | Total |
| Netherland, Sewell & Associates, Inc. |   | February 19, 2009                   |   | Canada                                   |   | nil                                                                                                    |   | 2,568,777 |   | nil |   | 2,568,777 |

 

|   | 5.     | In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we did not evaluate.                                               |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                            |
|   | 6.     | We have no responsibility to update our report referred to in paragraph 4 for events and circumstances occurring after its respective preparation date.                                                                                                                         |
|   |   |                                                                                                                                                                                                                                                                            |
|   | 7.     | Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery. |

 

 

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Executed as to our report referred to above:

 

|   |   |   | **NETHERLAND, SEWELL & ASSOCIATES, INC.**                     |
|--------|--------|--------|-------------------------------------------------------------------|
|   |   |   | Dallas, Texas, USA

March 13, 2009                                |
|        |   |   | /s/ C.H. (Scott) Rees III, P.E.                                   |
|   |   |   | C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer |

 

 

RCB:RMB

 

 

|   |  

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

  |   |
|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------|

 

 

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**SCHEDULE B**

**REPORT OF MANAGEMENT AND DIRECTORS**

**ON RESERVES ON OIL AND GAS DISCLOSURE**

Management of Compton Petroleum Corporation (the “**Company**”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which are estimates of proved reserves and probable            reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated 100% of the Company’s reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report.

The Engineering, Reserves and Operations Committee of the Board of Directors of the Company has:

 

|   | (a) | reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator;                                                                                  |
|--------|-----|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   | (b) | met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and |
|   | (c) | reviewed the reserves data with Management and the independent qualified reserves evaluator.                                                                                                        |

 

The Engineering, Reserves and Operations Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with Management. The Board of Directors has, on the recommendation of the Engineering, Reserves and Operations Committee, approved:

 

|   | (a) | the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; |
|--------|-----|--------------------------------------------------------------------------------------------------------------------------------------------|
|   | (b) | the filing of Form 51-102F2 which is the report of the independent qualified reserves evaluator on the reserves data; and                  |
|   | (c) | the content and filing of this report.                                                                                                     |

 

 

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

 

| (signed) “Tim Granger”

Tim Granger

President & CEO                                                | (signed) “Murray Stodalka”

Murray Stodalka

Vice President, Operations |
|---------------------------------------------------------------------------------------------------------------------|-------------------------------------------------------------------------------------|
| (signed) “Jeffrey Smith”

Jeffrey Smith

Chairman of the Engineering, Reserves and Operations Committee | (signed) “Mel Belich”

Mel Belich

Chairman of the Board                |

 

March 23, 2009

 

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**SCHEDULE C**

**COMPTON PETROLEUM CORPORATION**

**AUDIT, FINANCE AND RISK COMMITTEE**

**CHARTER**

**MANDATE OF THE COMMITTEE**

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

 

| 1. | the integrity of the Company's financial information and accounting, financial reporting encompassing the financial statements and the MD&A (as hereinafter defined), and auditing processes; |
|----|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 2. | the internal and 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:

 

49 -

 

 

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| **(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.      | review the evaluation of internal controls by the external auditor with management and the Company's subsequent follow-up to any identified weaknesses;                                                                                                                                                                                                                                                                                                                    |
| 3.      | review, in conjunction with the Human Resources, Compensation, Environmental, Health and Safety Committee of the Board, the appointment of the Chief Financial Officer;                                                                                                                                                                                                                                                                                                    |
| 4.      | determine the appropriate resolution of conflicts of interest in respect of audit, finance and risk matters, properly directed to the Committee;                                                                                                                                                                                                                                                                                                                           |
| 5.      | review with management and the external auditor:                                                                                                                                                                                                                                                                                                                                                                                                                           |
|    | (a)                                                                                                                                                                                                                                                                                                                                                                                                                                                                        | in conjunction with the report of the external auditor, the Company's audited annual financial statements and the annual management’s discussion and analysis of financial conditions and results of operations ("MD&A"), and quarterly financial statements and MD&A, |
|    | (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; |
| 6.      | obtain an explanation from management of all significant variances between comparative reporting periods. The Committee shall review all financial statements and MD&A prior to their presentation to the Board for approval;                                                                                                                                                                                                                                          |
| 7.      | 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; |
| 8.      | 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                                                                                                                                                                                                                                                                                   |

 

 

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|                                         | than in the documents listed in section 7 above and periodically, at least annually, assess the adequacy of those procedures, as required by Multilateral Instrument 52-110, section 2.3;                                                                                                         |
|----------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 9.                                           | 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;                                                       |
| 10.                                          | discuss with the Company's General Counsel, at least annually, legal and regulatory matters that may have a material impact on the financial statements;                                                                                                                                          |
| 11.                                          | review with the Chief Financial Officer and the Chief Executive Officer of the Company their respective disclosures made to the Committee during the certification process as required by Multilateral Instrument 52-109, and in addition:                                                        |
|                                         | (a)                                                                                                                                                                                                                                                                                               | any significant deficiencies or material weaknesses in the design or operation of internal controls, |
|                                         | (b)                                                                                                                                                                                                                                                                                               | any fraud involving management or other employees who have a significant role in the Company's internal controls, |
|                                         | (c)                                                                                                                                                                                                                                                                                               | any other obligations arising from certification, and |
|                                         | (d)                                                                                                                                                                                                                                                                                               | any significant changes in the internal controls; |
| 12.                                          | review with management, internal audit, and the external auditor and as required by the Corporate Governance Committee, the Company's Code of Business Conduct and Ethics;                                                                                                                        |
| 13.                                          | 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 |
| 14.                                          | review with management the details of all transactions between the Company and parties related to the Company.                                                                                                                                                                                    |
| **(B)**                                      | **Oversight of the Internal Auditor**                                                                                                                                                                                                                                                             |
| 1.                                           | review the audit plans of the internal auditors of the Company including the degree of coordination between such plan and that of the external auditors and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts; |
| 2.                                           | review the significant findings prepared by the internal auditing department and recommendations issued by the Company or by any external party relating to internal audit issues, together with management’s response thereto;                                                             |
| 3.                                           | appropriate review of compliance with the Company’s policies;                                                                                                                                                                                                                               |

 

 

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| 4.                                           | review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including reports from the internal audit department on its audit process;                                                                                                                                                                                                                                                                                                                                                                                                                                |
|----------------------------------------------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 5.                                           | ensure the internal auditor has access to the Chair of the Audit, Finance and Risk Committee and such chair meet separately with the head of internal audit to review any problems or difficulties that may have been encountered and specifically:                                                                                                                                                                                                                                                                                                                                                                                               |
|                                         | (a)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               | any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management; |
|                                         | (b)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               | any changes required in the planned scope of the internal audit; and |
|                                         | (c)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               | the internal audit department responsibilities, budget and staffing; |
| and to report to the Board on such meetings; |
| 6.                                           | review and concur in the appointment, compensation, replacement, reassignment, or dismissal of the head of internal audit.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |
| **(C)**                                      | **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;                                                                                                                                                                                                                                                                                                                                                                                                                                                    |

 

 

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| 8.      | review all reportable events, including disagreements, unresolved issues and consultations, as defined in National Instruments 51-102, on a routine basis, whether or not there is to be a change of external auditor;                                                                     |
|---------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 9.      | review all issues and documentation related to a change of external auditor, including information to be included in the Change of Auditor Notice and documentation called for under National Instruments 51-102 and the planned steps for an orderly transition period;                   |
| 10.     | appropriately supervise and evaluate the performance of the external auditor and lead audit partner, and report conclusions to the Board;                                                                                                                                                  |
| 11.     | review and approve the Company's hiring policies regarding partners, employees, former partners and former employees of the current and previous external auditors of the Company;                                                                                                         |
| 12.     | oversee the rotation of audit partners as required by applicable regulation and, in order to ensure continuing auditor independence, consider annually whether it is appropriate to adopt a policy of rotating the Company's external auditing firm on a regular basis;                    |
| 13.     | pre-approve the nature of, and fees for, all audit, review, attestation and significant non-audit services provided by the external auditor, prior to engagement, and disclose such pre-approvals in accordance with applicable securities law;                                            |
| 14.     | consider the effect of significant non-audit engagements on the independence of the external auditor; and                                                                                                                                                                                  |
| 15.     | provide to the external auditor any information and explanations, and access to records, documents, books, accounts and vouchers of the Company that are, in the opinion of the external auditor, necessary to make the examinations and reports required under legislation or regulation. |
| **(D)** | **Oversight of Financial Reporting and Accounting Policies**                                                                                                                                                                                                                               |
| 1.      | review with management, internal audit, 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;                                                                                             |

 

 

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| 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.                                                                                                                                                                                 |
| **(E)**                                       | **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 financial transactions entered into pursuant to such policies mitigating risk with respect to commodity prices, interest rates, and foreign exchange;                                                    |
| 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.                                                                   |
| **(F)**                                       | **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;                                                                                                                                                                                                                |
| 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:                                                                                                                                                                                                                                                                        |

 

 

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|                             | (a)                                                                                                                                                                                                                                                                                     | inspecting any and all of the books, records and financial affairs of the Company, its subsidiaries and affiliates; and                                                                                                                                                                                                                                                                                                                          |
|----------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                             | (b)                                                                                                                                                                                                                                                                                     | meeting with any executive or employee of the Company with or without management to review such accounts, records and other matters as any member of the Committee considers necessary and appropriate;                                                                                                                                                                                                                                          |
| 8.                               | review when deemed necessary by the Committee any of the financial affairs of the Company, its subsidiaries or affiliates and make recommendations to the Board, to the external auditor, or to management, as appropriate;                                                             |
| 9.                               | consider and make recommendations to the Board with respect to any matters properly referred to the Committee by the Board;                                                                                                                                                             |
| 10.                              | perform any other activities consistent with this Charter as the Committee deems necessary or appropriate in order to carry out its mandate.                                                                                                                                            |
| **COMPOSITION OF THE COMMITTEE** |
| 1.                               | The Committee shall be comprised of at least three directors.                                                                                                                                                                                                                           |
| 2.                               | Each member of the Committee shall be “independent” as affirmatively determined by the Board, and as defined in the Company’s Standards of Independence attached hereto.                                                                                              |
| 3.                               | At least half of the members of the Committee must be resident Canadians, as that term is defined in the ABCA.                                                                                                                                                                          |
| 4.                               | The Board shall appoint the members of the Committee at the first meeting of the Board following each annual meeting ("Annual Meeting") of the shareholders of the Company.                                                                                                             |
| 5.                               | The Board shall appoint one member of the Committee to be the Chair of the Committee.                                                                                                                                                                                                   |
| 6.                               | A director appointed by the Board to the Committee shall be a member of the Committee until the next Annual Meeting or until his or her earlier resignation or removal by the Board. A member shall cease to be a member of the Committee upon ceasing to be a director of the Company. |
| 7.                               | The Board may remove or replace any member of the Committee at any time.                                                                                                                                                                                                                |
| 8.                               | The Company's Corporate Secretary, or in his or her absence, one of the persons present and 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; |

 

 

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|                          | (b)                                                                                                                                                                                                                                                                                                                                                                                                                         | A Committee member who is not financially literate may be appointed to the Committee provided that the member becomes financially literate within a reasonable period of time following his or her appointment; and                                                            |
|-------------------------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                          | (c)                                                                                                                                                                                                                                                                                                                                                                                                                         | At least one member of the Committee shall have accounting or related financial management expertise and, where possible, at least one member of the Committee shall qualify as an "audit committee financial expert" within the meaning of applicable securities legislation. |
| **MEETINGS OF THE COMMITTEE** |
| 1.                            | The Committee shall convene at such times and places designated by the Chair of the Committee, at least on a quarterly basis, and whenever a meeting is requested by the Board, a member of the Committee, the external auditor, or a senior officer of the Company. The Committee shall meet in separate sessions with management and the external auditor at                            each regularly scheduled meeting. |
| 2.                            | Notice of each meeting of the Committee shall be given to each member and to the external auditor, who shall be entitled to attend each meeting of the Committee.                                                                                                                                                                                                                                                           |
| 3.                            | Notice of a meeting of the Committee shall:                                                                                                                                                                                                                                                                                                                                                                                 |
|                          | (a)                                                                                                                                                                                                                                                                                                                                                                                                                         | be in writing (which may be communicated by electronic facsimile or other communication facilities),                                                                                                                                                                           |
|                          | (b)                                                                                                                                                                                                                                                                                                                                                                                                                         | state the nature of the business to be transacted at the meeting in reasonable detail,                                                                                                                                                                                         |
|                          | (c)                                                                                                                                                                                                                                                                                                                                                                                                                         | to the extent practicable, be accompanied by copies of documentation to be considered at the meeting, and                                                                                                                                                                      |
|                          | (d)                                                                                                                                                                                                                                                                                                                                                                                                                         | be given at least 24 hours preceding the time stipulated for the meeting.                                                                                                                                                                                                      |
| 4.                            | A quorum for the transaction of business at a meeting of the Committee shall consist of a majority of the members of the Committee.                                                                                                                                                                                                                                                                                         |
| 5.                            | A member of the Committee may participate in a meeting of the Committee by means of such telephonic, electronic or other communication facilities as permit all persons participating in the meeting to communicate adequately with each other. A member participating in such a meeting by any such means is deemed to be present at that meeting.                                                                         |
| 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                                                                                                                                                                                                                                  |

 

 

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|   | include copies of all resolutions passed at each meeting, and shall be available for review by members of the Committee, the Board, management and external auditor. |
|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

 

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**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 member1 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 partner2 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 |

 

_______________________

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.

 

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|   |   | 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 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 affiliated3 person of the Company.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |

 

 

 

_______________________

| 3 | Affiliated person of another person means: |
|---|--------------------------------------------|

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

(c) any person directly or indirectly controlling, controlled by, or under common control with, such other person;            (d) any officer, director, partner, copartner, or employee of such other person;            (e) if such other person is an investment company, any investment adviser thereof or any member of an advisory board thereof; and            (f) if such other person is an unincorporated investment company not having a Board of Directors, the depositor thereof.

 

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