Exhibit 99.1













ANNUAL INFORMATION FORM


For the Year Ended December31, 2010







February 24, 2011





TABLE OF CONTENTS





PageABBREVIATIONS AND CONVERSION FACTORS


2DEFINITIONS


3CORPORATE STRUCTURE


9GENERAL DEVELOPMENT OF THE BUSINESS


9RISK FACTORS


18STATEMENT OF RESERVES DATA


27DIVIDENDS


41CAPITAL STRUCTURE


41MARKET FOR SECURITIES


43CONFLICTS OF INTEREST


43INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS


43CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS


44MATERIAL CONTRACTS


44LEGAL PROCEEDINGS AND REGULATORY ACTIONS


45INTERESTS OF EXPERTS


45RATINGS


45DIRECTORS AND OFFICERS


46COMMITTEE INFORMATION


49TRANSFER AGENT AND REGISTRAR


50ADDITIONAL INFORMATION


50ADVISORIES


51SCHEDULE A REPORT ON RESERVES DATA BY INDEPENENT QUALIFIED RESERVES EVALUATOR OR AUDITOR


54SCHEDULE B REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES ON OIL AND GAS DISCLOSURE


56










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;




“gj” means gigajoule, a term used for measuring energy use, equal to 109 joules;




“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 Byboe
Mcfe
6.000cubic feet
cubic metres of gas
0.028cubic metres of gas
cubic feet
35.490bbls of oil
cubic metres
0.159cubic metres
bbls of oil
6.289gigajoule
thousand cubic feet of natural gas
0.95feet
metres
0.305metres
feet
3.281miles
kilometres
1.609kilometres
miles
0.621acres
hectares
0.400hectares
acres
2.500





Currency & Exchange Rate Information




All references to “$”, “Cdn$” and “dollars” in this AIF refer to Canadian dollars, unless otherwise stated. References to “US$” in this AIF, refer to United States dollars. The following table sets forth, for each of the years indicated, the year-end noon exchange rate, the average noon exchange rate and the high and low noon exchange rates of one U.S. dollar in exchange for Canadian dollars using information provided by the Bank of Canada.




Year Ended December 31,2010


2009High


$1.0778



$1.3000Low


$0.9946



$1.0292Average


$1.0299



$1.1420Year-End


$0.9946



$1.0466




The noon exchange rate on December 31, 2010, using information provided by the Bank of Canada for the conversion of Canadian dollars into United States dollars, was $1.00 equals US$1.0054.






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”).





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“AECO Daily Index” means the daily price as quoted in Canadian Enerdata’s Canadian Gas Price Reporter in the table entitled “Daily Spot Gas Price at AECO C & NOVA Inventory Transfer” in the column “Price ($/GJ)”, Sub column “Avg”, for each individual day.




“AECO Monthly Index” means the Alberta Gas Price at AECO C in $/GJ as published monthly by Canadian Enerdata Ltd. in the “Canadian Gas Price Reporter” in the table entitled “Canadian Natural Gas Supply Prices” and described in the first column, under “Alberta” as “AECO C & N.I.T. One-Month Spot**” under heading “$/GJ” under the column “Avg” for the delivery month.




“AIF” means this Annual Information Form.




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




“Corporation” or “Compton” or “we” means Compton Petroleum Corporation and its 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.




“Deep Basin” means the area situated along the north-eastern front of the Rocky Mountain belt, which is the deepest part of the Alberta synclinal sedimentary basin. It contains low-permeability gas reservoirs, featuring regionally pervasive gas accumulations down-dip of regional aquifers.




“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.




“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




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(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.




“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 Corporation 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




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




(b)
the total number of wells in which the Corporation has an interest; or




(c)
the total area of properties in which the Corporation has an interest.




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




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




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




“net” means:




(a)
the Corporation’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 Corporation’s working interest in each of its gross wells; or




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




“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 Corporation participates in the operation of properties or otherwise serves as producer of the underlying reserves (in contrast to being an independent purchaser, broker, dealer, or importer).




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




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




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




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




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




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




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




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“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 Corporation 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.




“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.




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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 Corporation’s name to Compton Petroleum Corporation and the Corporation 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.




Compton’s head and principal office is located at Suite 500, 850 – 2ndStreet S.W., Calgary, Alberta, Canada, T2P 0R8.  Compton’s registered office is located at Suite 4300 Bankers Hall West, 888 – 3rdStreet, S.W., Calgary, Alberta, Canada, T2P 5C5.




WIN Energy (Montana) Inc., formed under the laws of Montana, is a wholly-owned subsidiary of Compton Petroleum Corporation.




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$193.5 million of 10% Senior Notes and US$45.0 million of 10% Mandatory Convertible Notes issued by Compton Petroleum Finance Corporation and inter-corporate indebtedness.  The registered office of Compton Petroleum Finance Corporation is 4300 Bankers Hall West, 888 – 3rd Street S.W., Calgary, Alberta, Canada, T2P 5C5.









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








GENERAL DEVELOPMENT OF THE BUSINESS




Compton is a public company actively engaged in the exploration, development and production of natural gas, natural gas liquids, and crude oil in western Canada.  The Corporation’s strategy is focused on creating value for shareholders by providing appropriate investment returns through the effective development and optimization of assets. Operations are located in the Deep Basin fairway of the Western Canada Sedimentary Basin (the “WCSB”). In this large geographical region, Compton pursues four Deep Basin natural gas plays: the Rock Creek sands at Niton in central Alberta, the Basal Quartz sands at High River in southern Alberta, the shallower Southern Plains sand play in southern Alberta and an




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exploratory play at Callum/Cowley/Todd Creek in the Foothills area of southern Alberta. Being in the Deep Basin, all areas have multi-zone potential, providing future development and exploration opportunity.  Compton is also focusing on developing its emerging oil potential in the southern plains area and in the Montana lands. Compton commenced operations in 1993 with $1 million of share capital and has since increased its natural gas portfolio, which currently represents approximately 84% of production and 88% of reserves. Compton’s shares are listed on the Toronto Stock Exchange under the symbol CMT.




Three Year History




Compton is active in three Deep Basin natural gas development plays: the Rock Creek sands at Niton in central Alberta, the Basal Quartz sands at High River in southern Alberta, and the shallower Southern Plains sand play in southern Alberta. In addition, the Corporation has an 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 2008, activities were directed towards the continued development of the Corporation’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. At this time, Compton had 32 horizontal gas wells that were multi-staged fractured – the majority of which were drilled and placed on production in 2008. Approximately 144% of the Corporation’s 2008 production was replaced at a proved FD&A of $20.29/boe, excluding technical revisions. Compton initiated and later terminated a corporate sales process during the latter part of the year. While interest was shown in the Corporation’s assets, none of the parties made an acceptable offer for all of Compton’s Common Shares, citing the public market turbulence at that time. In addition, Compton continued to divest non-core asset areas and, as such, Cecil, Zama, Thornbury and the Peace River Arch assets were sold for net proceeds of $203 million, resulting in a reduction of 305,606 net acres. All proceeds from the divestments were used to pay down bank 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.




In 2009, Compton modified several aspects of its business, creating a stronger and more stable organization. With continued low natural gas prices throughout the year, Management focused on a prudent business strategy that included executing a disciplined capital program – living within cash flow – and targeting a minimum 20% rate of return on the capital invested in its assets and increasing operating efficiencies. The Corporation’s cost structure decreased by 18% on a total dollar basis in 2009 through its focus on reducing operating, administrative and interest expenses, which provided additional capital for reinvestment. Compton reduced its debt level by 31% from 2008 with the proceeds of an equity issue and an overriding royalty (“ORR”)sale in 2009, strengthening its capital structure. Net proceeds of $161.9 million were raised through the issue of 138 million units composed of one common share (“Common Share”) and one share purchase warrant. The sale of the ORR provided proceeds of $80.8 million. The ORR represents 4.25% of the gross production revenue on the Corporation’s existing land base less certain transportation costs and marketing fees, calculated on a monthly basis. In addition, significant changes to the composition of the executive team and board added proven track records and strength to the Corporation. Drilling activities in 2009 primarily focused on the Niton property with one vertical and four horizontal wells successfully drilled by Compton. Horizontal drilling and completion costs were reduced by approximately 20%, strengthening the economics of the play.




In 2010, Management maintained its philosophy of living within cash flow, taking a prudent approach in its capital investment decisions and focusing its development strategy to optimize asset value, emphasize cost reduction, and carefully manage its capital structure. Compton focused its field activities on




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optimizing production from existing wells and drilling processes, improving operating efficiencies and well economics. As a result, cash flow benefited from volumes that exceeded guidance due to improvements in well performance and initial production rates as well as reduced costs, which somewhat offset the impact of lower natural gas prices. In addition, the Corporation began development of its emerging oil properties with drilling in the Southern Plains area. Compton closed the final 0.75% of the ORR transaction in 2010, bringing the total overriding royalty obligation to 5.0%.  Compton also completed the sale a portion of its natural gas assets located in the Niton and Gilby areas in Central Alberta for gross proceeds of $150.2 million.




In October 2010, Compton completed a Plan of Arrangement (the “Arrangement”) and recapitalization of its capital structure, exchanging all of Compton’s US$450.0 million Notes for a combination of:




·
US$193.5 million 10% notes due 2017 (the “Senior Notes”);




·
US$45.0 million 10% notes due September 2011 (the “Mandatory Convertible Notes”); and




·
US$184.5 million of cash.




This resulted in an overall reduction of the Corporation’s total debt amount outstanding by approximately 33% to $382.8 million at December 31, 2010 from $568.9 million, repositioning its capital structure and providing improved debt levels going forward. In addition, two new members were added to the Credit Facility syndicate, and the interest margin was reduced by 0.5% from previous levels.




2010 Reorganization




In December 2010 Compton implemented a series of transactions designed to simplify Compton’s corporate structure consisting of the following steps:




·
effective December 10, 2010, Compton transferred a nominal partnership interest in Compton Petroleum (partnership) to Compton Petroleum Holdings Corporation;




·
effective December 11, 2010, Compton Petroleum Finance Corporation transferred all of the issued and outstanding common shares of Hornet Energy Ltd. to Compton;




·
effective December 30, 2010, Hornet Energy Ltd. was liquidated and dissolved and subsequently Compton settled its inter-corporate debt with, and assumed the accounts payable of, Compton Petroleum (partnership); and




·
effective December 31, 2010, Compton Petroleum Holdings Corporation was liquidated and dissolved and Compton Petroleum (partnership) ceased to exist.




Compton’s focus on evaluating assets, drilling and operating practices and implementing cost control initiatives has resulted in improved returns on investment. Management remains committed to maintaining its financial prudence and improving its capital efficiencies, focusing on proving the value of other key areas and horizons in the Corporation’s asset base.




DESCRIPTION OF THE BUSINESS




Business Plan and Operating Strategy




The Corporation’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 as appropriate. 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




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plan and its current exploration, exploitation, development, production, engineering, financial, and administrative functions.




The Corporation’s operating strategy includes the components set forth below:




Maximize Shareholder Value Through Accretive Investment Decisions. Compton will utilize a disciplined business model to focus on value creation when reinvesting internally generated cash flow, providing the Corporation 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. Compton developed a robust multi-year plan that provides strategic direction and plans for future value creation.




Implement Measured and Flexible Financial Approach.  Compton will take a flexible financial approach, adjusting its 2011 capital spending up or down, depending upon how economic circumstances unfold during the year, and utilize available cash flow and funds from other sources for capital expenditures.  Prudent financial management will allow the Corporation to live within its means and reduce internal cost structures while managing its corporate structure in periods of low commodity prices. Other components of Compton’s financial discipline include establishing appropriate leverage ratios and maintaining an active commodity hedging program.




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 geographical focus of the Corporation’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 within the WCSB.




Focus on Unconventional Natural Gas in Large Resource Plays.  Compton 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 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. In addition, the Corporation’s areas of large contiguous land provide economies of scale for development, increasing return on capital.




Focus on Emerging Oil Prospects.  Compton will increase the amount of oil in its production portfolio, which will improve the Corporation’s cash flow in the current economic cycle.  There are promising oil plays in the Southern Plains area and in Montana, where Ellerslie, Mannville and Bakken Formation wells are in production. Compton plans to increase its focus going forward on developing these prospects, maximizing the benefit of Compton’s significant upside potential through the multiple zone development opportunities of its contiguous land blocks.




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 Corporation’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.




Operate Efficiently to Maximize Return on Investment.  Compton is committed to providing optimal returns from funds spent on operations, whether for drilling or operating costs. As a result, Management is focused on increasing operating efficiencies and production rates while decreasing drilling costs to achieve a minimum 20% rate of return on capital investments, and lowering operating costs with a goal of




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becoming a low cost producer (first quartile) compared with its peers. Compton believes that the prudent management of its assets will provide attractive returns on investment for its shareholders.




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. Compton has four Deep Basin development gas plays: the Rock Creek sands and other zones at Niton in central Alberta, the Basal Quartz sands at High River in southern Alberta, the shallower Southern Plains sand play in southern Alberta, and an exploratory play at Callum/Cowley/Todd Creek in the Foothills area of southern Alberta, which is a thrusted over-pressured Belly River sand formation. In addition, the Corporation is focused on developing its emerging oil plays in the Southern Plains: the Ellerslie, Mannville and Alberta Bakken/Big Valley Formations. 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




Niton (Central Alberta)




The Niton areas are multi-zone liquids rich, tight gas plays with production primarily coming from Jurassic Rock Creek, and Mannville Ellerslie sands. Compton has drilled over 205 wells to date on its 245 gross sections of controlled land in this area, where it has an average 73% working interest.




The Rock Creek play’s variable permeability and water-free nature lends itself well to horizontal drilling and multistage fracturing. Compton has been a leader in developing this play in Niton with 36 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 can result in attractive economics. The excellent drilling and economic results achieved in Niton in 2009 continued into 2010.  In 2010, Compton drilled two vertical and four horizontal wells targeting the Rock Creek formation in Niton and participated in an additional seven non-operated horizontal and vertical wells at Niton.




Improved drilling processes in 2010 at Niton resulted in higher average initial production rates and lower drilling costs. The six Rock Creek wells drilled over the year performed better than wells drilled in the past with average production rates of 2.5 MMcf/d and 30 bbl/MMcf per well in the first month of production. Compton reduced individual well drilling costs by 15% to 20% compared to historic drilling programs in 2009 while increasing the length of the horizontal sections.  With these improvements, a Rock Creek well drilled during the fourth quarter 2010 had an initial test rate of 5.5 MMcf/d with 30 bbl/MMcf of liquids. The well was on production in late February 2011 at approximately 3.3 MMcf/d and 35 bbl/MMcf of liquids. In addition, Compton’s focus on optimization and reliability enhanced base production. The continued strength from operations in the Niton area was the major contributor to sustained volumes in this area.




In 2011, Compton will focus on the development of the liquids-rich, high return Rock Creek formation at Niton, where the Corporation can generate strong rates-of-return. This area has multi-zone potential, providing the opportunity to expand the Corporation’s development base by moving into other geological horizons. The majority of these formations occur above the Rock Creek zone and are being exploited by other operators either vertically or horizontally. Compton intends to continue technical work to better understand these other uphole zones above the Rock Creek using horizontal drilling with multi-stage fracturing. During 2010, the Corporation began testing some of these uphole zones to further evaluate the area’s potential. A Spirit River Formation vertical well was drilled in late 2010 and brought on production at 1 MMcf/d. The results from this well support further development in the Spirit River Formation, reinforcing Niton’s multi-zone potential. This evaluation and testing may lead to new drilling programs in the future, supplementing the growth potential from the Rock Creek formation.




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High River (Southern Alberta)




Discovered by Compton in 1999, the High River 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 173 gross sections with an average 83% working interest in this area that is prospective for the Basal Quartz Pool. This pool has cumulative production of 127 BCF. In 2010, the pool produced 27 MMcf/d from the Basal quartz formation in 100 wells over five townships. With an annual pool wide base decline of 14%, the pool is an asset with predictable, stable, water free production of liquids rich gas.




The High River 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 obtained approval 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 the value of the Corporation’s development strategy. The 12 remaining sections have sufficient drainage with current well densities to adequately access the reservoir.




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. A key component of success in this area will be to minimize drilling and completion costs. In 2009 and 2010, Compton completed meshing the engineering and geological data to better understand the unexploited parts of the reservoir and target horizontal wells in this formation. Management then focused on refining the drilling and fracture design, and applying the knowledge gained through horizontal drilling to increase operational efficiencies and economics. In 2010, Compton reinitiated development programs at High River to enhance asset value following a complete asset review. Management is in the process of completing and evaluating the drilled wells, the results of which will determine future potential for the formation.




Additionally, two wells targeting the Basal Quartz Formation were refractured in 2010, resulting in combined average production of 450 Mcf/d, which was 4.5-times previous levels. Refracturing a well in an existing producing tight sand zone can open new pathways to access gas-charged rock and increase production at lower capital costs. With this success, Compton has identified additional future refracture locations from its inventory of over 100 existing producing vertical wells at High River.




Southern Plains (Southern Alberta)




The Southern Plains and overlying Edmonton Horseshoe Canyon shallow gas zones consist 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.




With control of 866 gross sections of land at an average 87% working interest, this land base provides a significant multi-year, low risk drilling inventory at two to four wells per section. At year-end, the Corporation was producing 30MMcf/d from the Southern Plains area.  Ample infrastructure is in place in the area for future production increases with 31,000 horsepower of compression and approximately 1,300 kilometres of pipeline




In 2010, six Belly River Formation wells were drilled and brought on production. Production rates exceed historical averages, reflecting the success of Compton’s ongoing emphasis on identifying optimal Belly River targets. Detailed analysis of the reservoir was completed, identifying several deeper opportunities for development.




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The shift in focus to deeper, higher rate targets in the Southern Plains area commenced in 2010 with three successful operations. One Glauconite drill yielded an initial rate of 1.5 MMcf/d and two Glauconite recompletions averaged 0.75 MMcf/d. With this success, Compton will continue to focus its investment on deeper targets in the Southern Plains, providing additional opportunities for the Corporation. In addition, an Ellerslie Formation horizontal oil well was drilled in late 2010. Initial indications are promising with approximately 700 metres of pay being encountered in the wellbore.




In 2011, Compton will focus on its emerging oil opportunities in the Southern Plains. Further development of the Ellerslie and Mannville Formations is planned, which provides significant upside potential for the Corporation. Compton will also pursue the development of its 24 net prospective sections of Alberta Bakken oil prospects, targeting the Big Valley Formation. There is potential to further reduce operating costs and optimize operations in this area, which will further improve the economics of the play.






Exploratory Properties




Callum-Cowley & Todd Creek (Foothills Area, Southern Alberta)




Compton controls 189 gross sections at an average 89% working interest in the Foothills area of southern Alberta, and has drilled 41 wells to date, 28 of which are producing.




The Callum-Cowley area is unique in western Canada consisting of a series of over-pressured, thrusted, multi-stacked tight gas-saturated, 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.




The contortion of the tight sand layers creates fractures, greatly enhancing permeability while creating conduits to the tighter gas-charged portion of the rock. Compton targets its drilling to access locations with these fractures, which is crucial to better access natural gas flows and increase the economics of the play. While there is substantial well core data in the area, additional geochemical work is being done to determine placement of the gas, characteristics of the rock and proper extraction techniques. In 2010, Compton drilled two wells in the Callum/Cowley area. The first well resulted in initial production of 750 mcf/d and the second well is in the process of being evaluated.




At Todd Creek, Compton is pursuing an exciting new play. In 2008, a new zone was successfully completed in an existing wellbore. In 2009, Compton commenced drilling a step-out well located close to the 2008 discovery well completed that was tied-in at 2.6 MMcf/d. The well has been drilled, completed and tied-in and is producing at 2.7 MMcf/d.




Alberta Bakken (Montana, U.S.)




In 2010, the Alberta Bakken Fairway, which runs through Alberta and Montana, attracted more industry attention. Compton holds 79,000 net acres of land on the Blood Indian Reserve in Montana through the previous acquisition of WIN Energy. The Corporation’s acreage has a long tenure (expires in 2017) and has one well previously drilled on it. Further exploration and evaluation of this area would be necessary to determine the potential of this property. In 2011, Compton intends to initiate a preliminary evaluation of the area in order to determine potential next steps.




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Principal Markets and Distribution Methods




Compton’s natural gas production is sold to credit worthy counterparties under contracts between AECO Daily Index price sales and AECO Monthly Index price sales, with transactions at Nova Inventory Transfer. A small portion (3%) of the sales portfolio is dedicated to aggregator pools under pricing that reflects the AECO Indices. Natural gas is transported through regulated pipelines in the Province of Alberta at tariffs which require either Provincial or Federal regulatory approval.




The Corporation’s crude oil sales are priced at market using Edmonton postings as a benchmark and are typically 30-day evergreen contracts.  Natural gas liquids are priced on an annual basis with respect to product premiums with the base price for each component reflecting posted prices.  Crude oil and ngls are transported to the point of sale to credit worthy counterparties using a combination of pipelines and trucking services.




Cycles




The petroleum industry is both cyclical and seasonal in nature. The winter-summer cycle affects certain aspects of the business such as commodity prices and the ability to drill on certain properties during spring break-up. The price per barrel received by the Corporation is weighted to North American natural gas prices and can be adversely affected by mild weather conditions. In early 2009, excess natural gas supplies reduced commodity prices and resulted in a decrease in the price received by Compton. This pressure continued to be experienced through 2010 and into 2011.




Environmental Policies




Compton expects excellence in health, safety and environmental performance and is committed to conducting all operations in a safe manner that minimizes environmental impact, while meeting regulatory requirements and corporate standards. Compton maintains a comprehensive range of internal programs and controls to promote regulatory compliance and an appropriate level of safety and environmental protection in all of its operations. Its proactive program includes annual environmental compliance audits and inspection programs to ensure the Corporation’s facilities continually meet or exceed regulatory standards. Compton 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, reflecting the Corporation’s commitment to protecting the environmental quality of the areas in which it operates.




Compton views and treats the southern Alberta Foothills region as a unique environmental eco-system. Together with a number of southern Alberta ranching operations, the Corporation is completing a rangeland health assessment that addresses optimal ways to restore these eco-systems to their natural state. This includes providing funding of studies on native rough fescue grasses by the University of Alberta, as well as working closely with both industry and landowner work groups.




The Corporation carries out its activities in compliance with all relevant regulations and industry best practices. Compton’s Reserves, Operations and Environmental, Health and Safety Committee have oversight responsibilities for the Corporation’s overall policies and guidelines with respect to (a) engineering, reserves, operations, (b) the environment, and (c) health and safety. The Committee’s Charter can be located on the Corporation’s website at www.comptonpetroleum.com.




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




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Southern Alberta.  Compton does not have an ownership position in MPP. However, the Corporation through a management agreement manages the activities of MPP and is considered to be the primary beneficiary of MPP’s operations.  The results of the midstream activities are immaterial to Compton’s consolidated financial condition.




In 2009, Compton completed the renegotiation of the MPP processing and other related agreements for a further term of five years, expiring on April 30, 2014, at which time Compton may renew the agreement under terms determined at that time or purchase the MPP units for the predetermined amount of $27.8 million. In the event that the Corporation does not renew the processing agreement or exercise the purchase option, the partner may dispose of the partnership units to an independent third party. In connection with the renewal, Compton has reclassified a portion of the non-controlling interest associated with MPP as MPP term financing. MPP term financing is included as a liability in the consolidated financial statements of the Corporation.




Bank Debt, Senior Notes and Mandatory Convertible Notes




Compton’s outstanding bank debt at December 31, 2010 of $147.3 million was drawn on a revolving term facility authorized at $155.0 million and a revolving working capital facility authorized at $15.0 million (for a total of $170.0 million – together the “Credit Facilities”).  The Credit Facilities were renewed on June 30, 2010 for a period of 366 days until July 1, 2011, subject to review in June 2011. If the Credit Facilities are not extended at lenders option in 2011, the Credit Facilities will mature 366 days later on July 2, 2012. Compton expects that the Credit Facilities will be renewed in 2011 for a further 366-day period; total credit available under the facilities will be dependent on the borrowing base of Compton at that time. The Credit Facility is subject to re-determination of the borrowing base twice a year at December 31 and May 31. The borrowing base of the Credit Facilities is determined based on, among other things, the Corporation’s current reserve report, results of operations, the lenders view of the current and forecasted commodity prices and the current economic environment.




The Credit Facilities provide that advances may be made by way of prime loans, bankers’ acceptances, US base rate loans, LIBOR loans and letters of credit.  Advances will bear interest at the applicable lending rate plus a margin based on Compton’s debt to trailing cash flow ratio.  The Credit Facilities is secured by a fixed and floating charge debenture on the assets of the Corporation.




Compton’s outstanding debentures are composed of US$193.5 million of 10% Senior Notes due 2017 and US$45 million of 10% Mandatory Convertible Notes due September 15, 2011. The 2011 Mandatory Convertible Notes are redeemable, in whole or in part, prior to maturity at face value.  Redemption is required at maturity, or in the event any share issuance proceeds are received prior to the maturity date. Management anticipates redemption of the 2011 Mandatory Convertible Notes for cash in 2011 prior to maturity.




The indentures governing the Senior Notes and the Mandatory Convertible Notes each limit the extent to which Compton can incur incremental debt and requires the Corporation to meet a fixed charge coverage ratio test (“Ratio”) and an Adjusted Consolidated Net Tangible Asset Value (“ACNTA”) test if the Ratio test is not met.  At each quarter end, the Ratio must exceed a trailing four quarters 2.5 to 1 threshold.  If the Ratio is less than 2.5 to 1, the amount of debt senior in priority to the Senior Notes and the Mandatory Convertible Notes that the Corporation may incur is limited to the value calculated under the ACNTA test.




At December 31, 2010, the Ratio was 2.16 to 1, which was below the minimum requirement and thereby restricts the amount of incremental borrowings the Corporation may incur.  Based on the ACNTA calculation, Compton may incur up to $278.7 million under the Credit Facilities and certain other




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permitted debt until the time when the ratio exceeds 2.5 to 1.  Management does not anticipate these restrictions to have any limiting or adverse effect on the operations of the Corporation.




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 Corporation expects to be able to attract and maintain appropriately qualified employees in 2011.




Employees




As at December 31, 2010, Compton had 100 full-time equivalent employees in its Calgary office and 51 full-time equivalent 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




Following is a list of risks that Compton faces in its normal course of business. If any of these risks actually occur, Compton’s business, financial condition, results of operations, cash flows and prospects could be harmed. Such risks and uncertainties are not the only ones the Corporation faces. Additional risks and uncertainties, including those of which Management is currently unaware or that are deemed immaterial, may also adversely affect Compton’s business, financial condition, results of operations, cash flows and prospects.




Current Global Financial Condition




Operations are affected by local, national and worldwide economic conditions and the condition of the oil and gas industry.  Recent disruptions in the credit markets and concerns about the global economy have had an adverse impact on global financial markets. These and other factors may affect Compton’s ability to obtain equity or debt financing in the future on favourable terms. Additionally, these factors, as well as other related factors, may cause decreases in the Corporation’s asset values that may be other than temporary, which may result in impairment losses. If such increased levels of volatility and market turmoil continue, or if more extensive disruptions of the global financial markets occur, operations could be adversely impacted and the trading price of Compton’s Common Shares may be adversely affected.




Additional Funding Requirements




Compton’s ongoing activities may not generate sufficient cash flow from operations to fund future exploration, development, or acquisition programs.  The Corporation 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




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opportunities, and reduce or terminate operations.  This may result in the Corporation not being able to replace its reserves or maintain production, which will have an adverse effect on its financial position. Failure to obtain additional funding may also result in the Corporation failing to meet financial obligations as they come due or may result in the acceleration of the Corporation’s debt.




Liquidity Risk




Liquidity risk is the risk that the Corporation is not able to meet its financial obligations as they fall due. If the Credit Facilities are not renewed on June 30, 2011, Compton’s $170.0 million term Credit Facilities will mature on July 2, 2012. The lenders under the Credit Facilities will reassess the borrowing base semi-annually on May 31 and December 31, which review may change the amount that the Corporation may borrow under its Credit Facilities. The Corporation expects that the Credit Facilities will be renewed in 2011 for a further 366-day period; total credit available under the facilities will be dependent on the borrowing base of Compton at that time. As at December 31, 2010, Compton had $147.3 million outstanding under its Credit Facilities.




Compton has a significant amount of indebtedness that is currently affecting, and is likely to continue to affect, its financial position and operational flexibility. As of December 31, 2010, Compton, on a consolidated basis, had outstanding total net debt of approximately $449.6 million, of which approximately $191.2 million was secured debt, which includes bank debt, secured by a first fixed and floating charge debenture, and MPP term financing, secured by the underlying gas plant assets.  Compton’s substantial amount of debt could have important negative consequences, such as:




·
limiting its ability to obtain additional financing, if needed, or refinancing, when needed, for debt service requirements, working capital, capital expenditures or other purposes;




·
increasing its vulnerability to current and future adverse economic and industry conditions;




·
requiring Compton to dedicate a substantial portion of its cash flows from operations to make payments on its debt;




·
causing Compton to monetize assets on terms that may be unfavourable to Compton;




·
causing Compton to offer debt or equity securities on terms that may not be favourable to Compton or its shareholders;




·
reducing funds available for operations, future business opportunities or other purposes;




·
limiting Compton‘s flexibility in planning for, or reacting to, changes and opportunities in its business and its industry;




·
increasing employee turnover and uncertainty, diverting management’s attention from routine business and hindering its ability to recruit qualified employees; and




·
placing Compton at a competitive disadvantage compared to its competitors that have less debt.




Compton’s Credit Facilities, the Senior Note Indenture and the Mandatory Convertible Note Indenture and the terms and conditions of its other indebtedness may permit Compton to incur or guarantee additional indebtedness, including secured indebtedness in some circumstances. To the extent, Compton incurs additional indebtedness, some or all of the risks discussed above will increase. The terms of this indebtedness restrict Compton’s ability to sell assets, apply the proceeds of such sales, and reinvest in its business.  As a result, some or all of the risks discussed above may increase.




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Restrictive covenants in agreements governing Compton’s indebtedness may reduce Compton’s operational and financial flexibility, which may prevent Compton from capitalizing on business opportunities.




The terms of the agreements governing Compton’s indebtedness contain a number of operating and financial covenants restricting its ability to among other things:




·
incur additional debt;




·
create liens on assets;




·
pay dividends or distributions on, or redeem or repurchase, its capital stock;




·
make investments;




·
engage in sale and leaseback transactions;




·
engage in transactions with affiliates;




·
transfer or sell assets;




·
issue and sell equity interests in Compton’s wholly-owned subsidiaries;




·
guarantee debt;




·
restrict dividends and other payments to the Corporation;




·
consolidate, merge or transfer all or substantially all of Compton's assets and the assets of its subsidiaries; and




·
engage in unrelated businesses.




Each of the Credit Facilities, the Senior Note Indenture and the Mandatory Convertible Note Indenture limit the extent to which the Corporation can incur other debt and require it to meet a fixed charge coverage ratio test and the ACNTA test. At each quarter end, the fixed charge coverage ratio must exceed a 2.5 to 1 threshold and the value calculated under the ACNTA test must exceed borrowings under the Credit Facilities. Failure to meet the fixed charge coverage ratio limits Compton from incurring new debt to the ACNTA calculated value. At December 31, 2010, the fixed charge coverage test resulted in a ratio of 2.16 to 1 (2.0 to 1 at December 31, 2009). The December 31, 2010 ratio calculation falls below the minimum requirement and thereby restricts the amount of incremental borrowings the Corporation may incur. The Corporation may incur up to $278.7 million under the Credit Facilities and certain other permitted debt until the time when the ratio exceeds 2.5 to 1. Management does not anticipate these restrictions to have any limiting or adverse effect on the operations of the Corporation.




The calculation of the ACNTA was $278.3 million at December 31, 2010 ($263.4 million at December 31, 2009), which was higher than the Credit Facilities authorized limits. Any reduction in Compton’s ability to access credit under the Credit Facilities, or requirement to pay amounts outstanding under the Note Indenture before its stated maturity date may result in the Corporation not being able to meet its financial obligations as they come due.




In addition, Compton’s ability to comply with such covenants and those contained in the agreements governing other debt to which Compton is or may become a party may be affected by events beyond its control, including prevailing economic, financial and industry conditions. Its failure to comply with these covenants could result in an event of default which, if not cured or waived, could result in an acceleration of its debt and cross-defaults under its other debt. This could require Compton to repay or repurchase debt prior to the date it would otherwise be due, which could adversely affect its financial condition.  Even if




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Compton is able to comply with all applicable covenants, the restrictions on its ability to manage its business in its sole discretion could adversely affect its business by, among other things, limiting its ability to take advantage of financings, mergers, acquisitions and other corporate opportunities that Compton believes would be beneficial to it.




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.




The Corporation’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 Corporation 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 Corporation.




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 Corporation’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 Corporation’s secured Credit Facilities are based upon the lenders’ estimate of the value of the Corporation’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 Corporation’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 Corporation’s wells depends on numerous factors beyond the Corporation’s control, including the availability and capacity of gas gathering systems, pipelines and processing facilities, and their proximity to the wells.  The Corporation 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 Corporation’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 Corporation’s reserves will deplete and, as a consequence, either




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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 Corporation’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 Corporation 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 Corporation 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 Corporation utilizes a team of highly qualified professionals with expertise and experience in these areas.  Compton assesses strategic acquisitions to complement existing activities while striving for a balance between exploration and lower risk development and exploitation prospects.




Uncertainty of Reserve Estimates




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




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




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




Difference in Reserves Reporting Practices between Canada and the United States




Compton reports its production and reserve quantities in accordance with Canadian practices and specifically in accordance with NI 51-101. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.




The Corporation incorporates additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. Compton follows the Canadian practice of reporting gross production and reserve volumes; however, it also follows the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). The Corporation also follows the Canadian practice of using




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forecast prices and costs when it estimates its reserves. However, Compton separately estimates its reserves using prices and costs held constant at the effective date of the reserve report in accordance with the Canadian reserve reporting requirements. These latter requirements are similar to the average constant pricing reserve methodology utilized in the United States.




Compton has included estimates of proved and proved plus probable reserves, as well as contingent resources in this AIF. Prior to January 1, 2010, the SEC generally prohibited the inclusion of estimates of probable and possible reserves and contingent resources in filings made with it by United States oil and gas companies. However, the SEC has adopted revisions to its oil and gas reporting rules that, effective as of January 1, 2010, among other things, modified the standards to establish proved reserves and permit disclosure of probable and possible reserves under certain circumstances. However, significant differences remain between the reserve categories and reserve reporting generally under Canadian and U.S. securities laws and rules.




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 that result in a shutdown or slowdown of operations will adversely affect the Corporation’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 Corporation 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 Corporation will be liable.  The location of operations near populated areas, including residential areas, commercial business centers, and industrial sites could increase these risks and hazards.  The Corporation 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 Corporation competes for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment,




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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 Corporation’s properties.  Compton’s inability to access the Corporation’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 Corporation 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.




Reliance on Key Employees




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




Market Price of the Common Shares




The price of Compton’s Common Shares is likely to be significantly affected by short-term changes in commodity prices and currency exchange fluctuation. Factors such as fluctuations in its operating results, the result of any public announcements made by the Corporation, and general market conditions can also have an adverse effect on the market price of securities. The trading price of Compton’s Common Shares has been and may continue to be subject to large fluctuations, which may result in losses to investors. The high and low closing sale prices of Common Shares on the TSX were $13.20 and $0.88 in 2008; $2.03 and $0.56 in 2009; and $1.11 and $0.39 in 2010, respectively.




The Corporation delisted from the NYSE on June 24, 2010. The high and low closing sale prices of Common Shares on the NYSE were US$12.94 and US$0.68 in 2008; US$1.75 and US$0.44 in 2009; and $1.16 and $0.609 in the period prior to delisting in 2010, respectively.




Potential Dilution




Management continually evaluates acquisition opportunities and recapitalization transactions, and although the Corporation is not currently party to any definitive agreements in respect of such transactions, it may engage in transactions that result in the issuance of additional Common Shares, which issuances may be dilutive. In October 2009, the Corporation issued 138 million warrants in connection




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with an equity transaction, which are exercisable at $1.55 per share at any time during two years following the transaction’s close. Other issuances of additional Common Shares may also result in dilution to the holders of the Common Shares.




Changes to the Alberta Royalty Regime
 
 On January 1, 2009 the Mines and Minerals (New Royalty Framework) Amendment Act, 2008 became law in Alberta.  This legislation implemented a new royalty framework (the “New Royalty Framework”) that involves an increase in the royalties collected by the Alberta government and changes 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 provide 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 an 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 provided (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.
 
 In March 11, 2010, the Alberta government announced the outcome of the Competitiveness Review. The outcome was that the maximum royalty rate for conventional oil will be reduced to 40%, and the maximum for methane and ethane will be reduced to 36%. New well royalty rates become a permanent feature of the royalty system effective May 2010. In addition, transitional royalty rates can only be elected until December 31, 2010. Well events that have elected the transitional royalty can choose to opt out only between January 1, 2011, and February 15, 2011. Compton has elected to opt out on all but one Cowley well. The impact of these royalty changes is expected to be minimal considering the low gas prices forecast into 2011.
 
 Environmental Risks
 
 The Corporation 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.
 
 Compton is committed to minimizing any potential impact on the environment by ensuring its operations are performed at a high standard. As such, the Corporation’s regulatory compliance is above industry average and it has not experienced any material non-compliance actions. In addition, there are no reputational issues or litigation from environmental damage.




- 25 -




Trends and Uncertainties




The oil and gas industry is subject to extensive environmental laws and regulations pursuant to local, provincial, and federal legislation. Compliance with any new legislation may require significant expenditures and a failure to comply may result in the issuance of shut-in or closure 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 Corporation’s financial condition. Furthermore, future changes in environmental laws and regulations, including adoption of stricter standards or more stringent enforcement, could result in increased costs, incurred liability, and increased capital expenditures and operating costs, any of which could have a material adverse effect on Compton’s financial condition.




As Compton’s production facilities and other operations and activities emit greenhouse gases, the Corporation may be subject to emissions targets and may subject the Corporation to legislation that will require increasingly strict regulation with respect to the emissions of greenhouse gases. The regulatory uncertainty around climate change legislation continues in Canada. Currently, the Alberta Regulatory Effectiveness Project is being debated at the Ministerial level and the changes contemplated could significantly alter the regulatory regime in Alberta. Nevertheless, if the objects of the project are met and there is improved effectiveness and efficiency, the industry as a whole should see some financial benefits from these actions.  Compton views these potential changes as being positive for continued operations and development in its key operating areas in Alberta.




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 Corporation, its operations and financial condition at this time.




Environmental Liabilities




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 Corporation’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.




There have been no significant environmental spills, releases or incidents with any material financial impact, no legal actions due to any environmental or safety events or incidents and no known material environmental contamination associated with historical practices or operations. However, as part of Compton’s reclamation and abandonment program, new sites will continue to be investigated which could result in an identified contaminated site in the future.




Asset Retirement Obligations(“ARO”)




Compton has not established a separate reclamation fund for the purpose of funding estimated 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.  It is not possible to predict Compton’s ability to fully fund the cost of all its future environmental, abandonment and reclamation obligations.




Compton does expect to incur site restoration costs over a prolonged period as wells reach the end of their economic life. Compton provides for future abandonment and reclamation costs in its financial statements




- 26 -




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.




There are significant uncertainties related to AROs and the impact on the financial statements could be material. The eventual timing of and costs for these AROs could differ from current estimates. The main factors that can cause expected cash flows to change are:




·
changes to laws and legislation;




·
construction of new facilities;




·
change in the reserve estimate and the resulting amendment to the life of the reserves; and




·
changes in technology.




STATEMENT OF RESERVES DATA




Compton’s interests in 100% of the Corporation’s natural gas and crude oil properties have been evaluated in a report (the “Reserves Report”) as of December 31, 2010, prepared by the independent international integrated petroleum engineering and geological firm, GLJ Petroleum Consultants Ltd. (“GLJ”).  For the 2010 reserve evaluation, Management decided to change reserve evaluators to GLJ from Netherland, Sewell & Associates, Inc., taking into account several factors. In the course of various recent asset sales, it was determined that most prospective buyers were Canadian and preferred to rely on the report of a recognized Canadian reserves evaluator. With Compton’s shares delisting from the New York Stock Exchange, the Corporation no longer had a compelling reason to continue to have its reserves evaluated by an evaluator based in the United States.  In addition, Management determined that the Corporation could achieve substantial cost savings by utilizing a Canadian reserves evaluator.




The following summary of the Corporation’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 Corporation and on GLJ’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 February 24, 2011.  The information being provided in this statement has an effective date of December 31, 2010 and a preparation date of January 21, 2011.




- 27 -




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.




Reserves Volumes and Values Based on Forecast Prices and Costs




A summary of the Corporation’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, 2010




Crude Oil


Natural Gas(2)


Ngls


TotalGross


Net


Gross


Net


Gross


Net


Gross


NetReserves Category(1)

(Mbbl)


(Mbbl)


(MMcf)


(MMcf)


(Mbbl)


(Mbbl)


(Mboe)


(Mboe)ProvedDeveloped producing


1,523



1,094



224,957



185,950



3,755



2,444



42,771



34,530Developed non-producing


252



212



13,884



11,809



221



157



2,787



2,337Undeveloped


212



163



59,115



49,943



1,451



1,055



11,516



9,541Total proved


1,988



1,469



297,957



247,702



5,427



3,656



57,074



46,408Probable


631



450



140,316



117,196



2,587



1,777



26,604



21,760Total proved plus probable


2,619



1,918



438,273



364,898



8,014



5,433



83,678



68,168


(1)
Numbers may not add due to rounding.


(2)
The solution and associated gas represents less than 3% of the Corporation’s proved plus probable natural gas reserves and is therefore considered immaterial and is not described separately.




The tables set forth below summarize the Corporation’s future net revenue as of December 31, 2010, based on forecast prices and cost assumptions.




Summary of Future Net Revenue as of December 31, 2010 (Forecast Prices)




Future Net Revenue ($000s)

Before Income Taxes Discounted at (%/year)Reserves Category (1)
0%

5%

10%

15%

20%ProvedDeveloped producing
$   1,073,033

$    677,759

$   492,161

$   394,387

$   331,595Developed non-producing
55,190

37,492

27,536

21,218

16,892Undeveloped
211,077

114,557

65,832

38,099

20,947Total proved
$   1,339,300

$    819,808

$   585,530

$   453,704

$   369,434Probable
682,290

300,908

165,853

102,438

67,186Total proved plus probable
$   2,021,590

$  1,120,716

$   751,382

$   556,142

$   436,620


(1)
Numbers may not add due to rounding.


(2)
Includes, at minimum, well abandonment costs (rather than total abandonment and reclamation costs).




- 28 -




Future Net Revenue ($000s)

After Income Taxes Discounted at (%/year)Reserves Category (1)
0%

5%

10%

15%

20%ProvedDeveloped producing
$      972,624

$    634,426

$    478,802

$    388,362

$  328,654Developed non-producing
41,392

30,156

23,427

18,829

15,462Undeveloped
157,834

86,177

49,465

28,133

14,632Total proved
$   1.171.850

$    750,759

$    551,694

$    435,325

$  358,748Probable
510,576

225,346

124,271

76,707

50,159Total proved plus probable
$   1,682,427

$    976,105

$    675,965

$    512,032

$  408,907


(1)
Numbers may not add due to rounding.




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





Total Future Net Revenue (Undiscounted) as of December 31, 2010 (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


3,051,024



540,554



958,015



171,026



42,129



1,339,300



167,450



1,171,850Proved plus probable


4,656,633



831,741



1,424,535



324,880



53,887



2,021,590



339,163



1,682,427


(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, 2010 (Forecast Prices)




Future Net Revenue

Before Income Taxes

(discounted at 10%/year)
Unit Value(3)Reserves Category
Production Group
($000s)
($/bbl)
($/Mcf)
($/BOE)Proved
Light & medium oil(1)
58,513
24.77

24.77Heavy oil(1)
1,329
19.12

19.12Natural gas(2)
525,688

1.99
11.95Total
585,530


12.62Proved plus probable
Light & medium oil(1)
71,117
22.94

22.94Heavy oil(1)
1,585
18.33

18.33Natural gas(2)
678,680

1.74
10.44Total
751,382


11.02


(1)
Includes solution gas and other by-products


(2)
Includes by-products but excluding solution gas


(3)
Unit values are based on net reserves




- 29 -





Pricing Assumptions




Future net revenue calculated using forecast prices and costs is based upon the price assumptions set out below. GLJ's January 1, 2011 price deck was used in estimating Compton’s reserves data as at December 31, 2010.




Summary of Forecast Pricing and Inflation Rate Assumptions as of January 1, 2010




Crude Oil

Natural Gas



NGLS



Sulphur

Inflation

Rate(1)

Exchange RateYear

WTI Cushing Oklahoma ($US/bbl)

Edmonton Par 40° API ($Cdn/bbl)

AECO C Spot

($Cdn/MMbtu)

Edmonton Propane ($Cdn/bbl)

Edmonton Butane ($Cdn/bbl)

Edmonton Pentanes+ ($Cdn/bbl)

Plant Gate ($Cdn/lt)

%/Year

$Cdn/$USForecast2011

88.00

86.22

4.16

54.32

67.26

90.54

140.00

2.0

0.982012

89.00

89.29

4.74

56.25

68.75

91.96

125.00

2.0

0.982013

90.00

90.92

5.31

57.28

70.01

92.74

125.00

2.0

0.982014

92.00

92.96

5.77

58.56

71.58

94.82

100.00

2.0

0.982015

95.17

96.19

6.22

60.60

74.07

98.12

100.00

2.0

0.982016

97.55

98.62

6.53

62.13

75.94

100.59

100.00

2.0

0.982017

100.26

101.39

6.76

63.87

78.07

103.42

102.00

2.0

0.982018

102.74

103.92

6.90

65.47

80.02

106.00

104.04

2.0

0.982019

105.45

106.68

7.06

67.21

82.15

108.82

106.12

2.0

0.982020

107.56

108.84

7.21

68.57

83.80

111.01

108.24

2.0

0.98There

-after

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

+2.0%/yr

2.0

0.98


(1)
Inflation rate for operating and capital costs.




The weighted average realized sales price for Compton for the year ended December 31, 2010 was $4.43/Mcf for natural gas, $76.14/bbl for crude oil, $63.63/bbl for ngls, and $31.00/lt for sulphur.




- 30 -




Reserves Reconciliation




The following table provides a summary of the changes in the Corporation’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


Natural GasGross Proved

(Mbbl)


Gross Probable

(Mbbl)


Gross Proved Plus Probable

(Mbbl)


Gross Proved

(MMcf)


Gross Probable (MMcf)


Gross Proved Plus Probable

(MMcf)December 31, 2009


3,779



2,808



6,587



496,544



340,388



836,932Extensions & improved recovery


173



84



257



20,664



(10,488
)


10,177Technical revisions


(593
)


(1,053
)


(1,646
)


(104,939
)


(165,083
)


(270,022
)Discoveries


-



-



-



-



-



-Acquisitions


-



-



-



-



-



-Dispositions


(1,023
)


(1,208
)


(2,231
)


(44,698
)


(26,954
)


(71,652
)Economic


-



-



-



(37,628
)


2,453



(35,175
)Production


(348
)


-



(348
)


(31,986
)


-



(31,986
)December31, 2010


1,988



631



2,619



297,957



140,316



438,273





(1)
Prepared by Management.  Numbers may not add due to rounding. (2)
The 2009 opening balances have been restated to exclude sulphur.
 (3)
Further explanation regarding the technical revisions may be found in the Company’s reserve news release dated February 24, 2011.




Ngls


Total ReservesGross Proved

(Mbbl)


Gross Probable

(Mbbl)


Gross Proved Plus Probable

(Mbbl)


Gross Proved

(Mboe)


Gross Probable

(Mboe)


Gross Proved Plus Probable

(Mboe)December 31, 2009


9,266



6,174



15,440



95,802



65,713



161,515Extensions & improved recovery


449



(311
)


140



4,066



(1,974
)


2,092Technical revisions


(1,851
)


(2,492
)


(4,343
)


(19,933
)


(31,058
)


(50,991
)Discoveries


-



-



-



-



-



-Acquisitions


-



-



-



-



-



-Dispositions


(1,355
)


(764
)


(2,119
)


(9,827
)


(6,464
)


(16,291
)Economic


(482
)


(21
)


(503
)


(6,753
)


387



(6,366
)Production


(601
)


-



(601
)


(6,281
)


-



(6,281
)December31, 2010


5,427



2,587



8,014



57,074



26,604



83,678


(1)
Prepared by Management.  Numbers may not add due to rounding.


(2)
The 2009 opening balances have been restated to exclude sulphur.


(3)
Further explanation regarding the technical revisions may be found in the Company’s reserve news release dated February 24, 2011.






Additional Information Relating to Reserves Data




Undeveloped Reserves Attributed to Current Year




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 (such as the cost of drilling a well) is required to render them capable of




- 31 -




production. They must fully meet the requirements of the reserves category (proved or probable) to which they are assigned.




i)
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 Corporation’s gathering systems. In addition, such reserves may relate to planned infill drilling locations.  The majority of these reserves are planned to be in production within a five-year timeframe.




The following table summarizes the Corporation’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 UndevelopedYear
Crude Oil

(Mbbl)
Natural Gas

(MMcf)
Ngls

(Mbbl)
Sulphur

(Mlt)2010
164
2,154
30
-2009
-
4,809
63
-2008
-
26,773
550
1412007 & before
54
59,074
1,019
-


(1)      First Attributed refers to reserves first attributed at year-end of the corresponding fiscal year.





ii)
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 2014.




The following table summarizes the Corporation’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 UndevelopedYear
Crude Oil

(Mbbl)
Natural Gas

(MMcf)
Ngls

(Mbbl)
Sulphur

(Mlt)2010
82
3,621
53
-2009
-
29,845
202
802008
45
30,065
647
4612007 & before
1,414
207,857
3,857
-


(1)      First Attributed refers to reserves first attributed at year-end of the corresponding fiscal year.





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





- 32 -




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 GLJ.




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)




Proved
Proved Plus ProbableYear
Forecast Prices and

Costs/Year ($000s)
Forecast Prices and

Costs/Year ($000s)Undiscounted2011
58,414
74,6472012
35,360
58,4722013
37,574
53,9612014
32,137
71,5872015
5,923
11,392Remaining
20,168
27,730Total undiscounted
189,576
297,789Total discounted @ 10% per year
147,514
229,902


(4)
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. Should the Corporation decide to accelerate its capital expenditure program, other sources of funding would need to be considered such as proceeds from:  (i) asset dispositions; (ii) farm-outs of existing lands; (iii) strategic alliances; (iv) debt financing when appropriate; and (v) new equity issues. Compton does not expect that the costs of funding its capital expenditures will have a material effect on the economics of the programs.




- 33 -




OTHER OIL AND GAS INFORMATION




Oil and Gas Properties and Wells




The following table summarizes the location of the Corporation’s interests as at December 31, 2010 in crude oil and natural gas wells that are producing or that the Corporation considers to be capable of production.




Area

Producing

CrudeOil Wells


Non-producing Crude Oil

Wells(2)


Producing Natural Gas Wells


Non-producing Natural Gas Wells(2)


Total WellsGross


Net


Gross


Net


Gross


Net


Gross


Net


Gross


NetAlbertaNiton(3)


27



22



6



6



112



80



22



18



167



126High River


3



3



-



-



116



98



8



7



127



108Southern Plains


25



14



4



3



685



600



7



6



721



623Foothills(4)


-



-



1



1



26



25



2



2



29



28Other


8



3



-



-



121



73



2



2



131



78Total wells


63



42



11



10



1,060



876



41



35



1,175



763


(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.


(3)
Includes Bigoray properties.


(4)
Callum, Cowley and Todd Creek properties.






Compton has high working interest and operatorship in its properties. As a result, the Corporation has ownership in its substantial established infrastructure, which allows flexibility to effectively manage area development and adjust operations accordingly. Key properties are described in “Principal Properties – Description of the Business”. Overall, Compton operates over 53,000 horsepower (“hp”) of compression totalling 200 MMcf/d of available field compression capacity, with over 95 MMcf/d of operated processing capacity with no mid-stream requirements (not including the Mazeppa Gas Processing Plant), and over 2,100 km of pipeline infrastructure in place.  Key facilities are as follows:




·
Mazeppa Gas Processing Plant: Compton provides the Management team and corporate guidance for the Mazeppa Processing Partnership, owned by Enstar (see “Description of the Business – Mazeppa Processing Partnership”).  This sour gas processing plant is located in the High River area at 2-35-19-28 W4M and currently has production capacity of 90 MMcf/d (licensed plant capacity) of sour natural gas and 45 MMcf/d of sweet natural gas.




·
High River: In the High River area there is 9,150 hp installed with a gas compression capacity of 42.5 MMcf/d and 270 km of pipeline infrastructure in place.  Volumes are all produced to the Mazeppa gas gathering system and sour gas processing plant.




·
Southern Alberta Foothills: The Callum and Cowley Gas Processing Plants with 100% plant ownership are currently capable of compressing 19 MMcf/d and ultimately processing 50 MMcf/d through the two existing facilities with the addition of field and/or plant compression.  There is currently over 60 km of pipeline infrastructure in the operating area with minimal third party infrastructure in place.





- 34 -




·
Bigoray and Pembina: This is Compton’s primary oil production property. Facilities consist of satellites, water injection facilities, and associated oil batteries. There is over 110 km of pipeline infrastructure in place in this operational area.




·
Edson, Niton, and McLeod: This foothills area property has compression capacity of 23 MMcf/d utilizing over 6,400 hp, including the Compton McLeod River Gas Processing Plant with 23 MMcf/d of capacity with 100% plant ownership.  Additionally, there is over 185 km of pipeline infrastructure in the area.




·
Shallow Gas Properties: Compton’s shallow gas infrastructure consists of over 95 MMcf/d of compression capacity utilizing 31,000 hp with over 1,300 km of pipeline infrastructure in place.  Final processing gas volumes are through a third party in some cases, but in many cases directly linked into the ATCO and Nova/TransCanada pipeline systems at multiple sales locations.




Compton’s wells to which reserves have been attributed and which are capable of producing but are not currently producing are provided in the table below, including the year in which they were designated this capacity. These wells are not producing for a number of reasons. There are a number of wells that are not tied-in due to surface issues with landowners. In addition, a number of wells are currently not economic to tie-in due to proximity of pipelines. Once prices improve, these wells can be tied-in.




Proven Developed Non-Producing WellsGas Wells


Oil WellsYear

Gross (100%)


Company Gross


Gross (100%)


Company Gross2004


1



1.0



-



-2005


12



8.0



-



-2006


12



8.3



-



-2007


10



7.5



1



1.02008


41



17.3



1



1.02009


14



8.5



-



-2010


41



35.0



11



10.0Total


131



85.6



13



12.0





Properties with No Attributed Reserves




The following table sets forth the Corporation’s undeveloped land holdings to which no proved reserves have been attributed as at December 31, 2010.




Area

Gross Acres


Net AcresAlbertaNiton


89,752



56,363High River/ Southern Plains


318,861



286,398Foothills(1)


60,919



50,654Other


93,603



79,009Total(2)


563,135



472,242


(1)
Callum, Cowley and Todd Creek properties.


(2)
Total land overstated due to multiple zones overlapping leases on various sections.




- 35 -




Compton expects that the rights to explore, develop and exploit approximately 78,729 net acres of undeveloped land may expire by December 31, 2011. Total land decreased from 2009 levels due to land expiries in areas viewed as less prospective by the Corporation. There are no material work commitments associated with the Corporation’s expiring undeveloped land holdings.




Compton holds interests in different formations under the same surface area pursuant to separate leases. The acreage is reported at the lease level, meaning formations held by separate leases under the same surface area are calculated separately to give gross and net acres.




Significant Factors or Uncertainties Relevant to Properties with No Attributed Reserves




There are various factors or uncertainties that could affect the anticipated development or production activities on properties with no attributed reserves.  They include:




·
Commodity Prices: The Corporation’s financial condition is substantially dependent on, and highly sensitive to, oil and gas commodity prices.  Lower commodity prices could change the economics of wells, which would affect the decision to develop certain areas.




·
Availability of Capital: Any material decline in prices could result in a material reduction of Compton’s cash flow, and hence, availability of capital for development.




·
Drilling Success Rate: As the Corporation expands its developed lands, future drilling is dependent upon the success rate of nearby wells.




·
Potential Development and Operating Costs: The amount of capital required to develop, operate and bring to market new areas will determine the economics and feasibility of the prospect.




Forward Contracts




In 2010, Compton’s realized average field price was $32.87/boe, comprised of $4.43/Mcf for natural gas and $65.71/bbl for liquids.  In 2009, Compton’s realized average field price was $28.90/boe, comprised of $4.16/Mcf for natural gas and $49.79/bbl for liquids.




Compton’s natural gas production is sold to credit worthy counterparties under contracts between AECO Daily Index price sales and AECO Monthly Index price sales, with transactions at Nova Inventory Transfer. A small portion (3%) of the sales portfolio is dedicated to aggregator pools under pricing that reflects the AECO Indices. Natural gas is transported through regulated pipelines in the Province of Alberta at tariffs which require either Provincial or Federal regulatory approval.




Compton’s crude oil sales are priced at market using Edmonton postings as a benchmark and are typically 30-day evergreen contracts.  Natural gas liquids are re-priced on an annual basis with respect to product premiums with the base price for each component reflecting posted prices.  Crude oil and ngls are transported to the point of sale to credit worthy counterparties using a combination of pipelines and trucking services.




From time to time, Compton may enter into hedging arrangements to mitigate commodity price risk and take advantage of opportunistic pricing.  Compton’s risk management policy provides comprehensive guidance that allows Management to enter into hedging transactions that mitigate risk from commodity prices, interest rates, foreign exchange rates and electricity prices. The policy specifically prohibits speculative hedging and sets limits on the volume and length of hedging contracts. The hedging policy




- 36 -




provides for hedging of up to 50% of gross budgeted volumes for any particular quarter for a period up to 24 months from the day they are entered into.




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 Corporation 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.




ARO cost calculations were derived from a combination of ERCB cost models, and typical industry experience and practices. The ARO process was reviewed, modified and reassessed throughout each quarter of 2010. Compton continues to evaluate the appropriate costs for both abandonment and reclamation based on industry standard cost calculations versus the Corporation’s expenditures. An ongoing asset inventory of all of Compton’s wells, pipelines and facilities is maintained and updated on a quarterly basis.




The deemed ARO liability for Compton’s well sites and facilities is the sum of the calculated abandonment and reclamation liabilities adjusted for designated status as an active, inactive, abandoned, or problem site. Information regarding environmental remediation costs and other liability issues for site specific concerns were derived from a review of historical audit and assessment reports of sites and facilities. An inflation rate of 2% and a credit adjusted risk free rate of 10.5% was used in the fair value calculation. Total asset retirement costs are estimated to be $346.8 million or $60.6 million when discounted at 10.5%, including the Mazeppa Processing Plant.  The undiscounted ARO associated with pipelines and facilities is estimated to be $43.9 million and is not deducted in estimating total future net revenue, as calculated in the Corporation’s reserve report.  The Corporation expects to pay approximately $8.9 million dollars in ARO costs between 2011 and 2015.




Financial and Operations Effects of Environmental Protection Requirements
  At present, the Corporation believes that it meets all existing environmental standards and regulations and includes appropriate amounts for environmental, health and safety costs in its annual capital and operating expenditure budget to continue to meet current environmental protection requirements. The Corporation does not anticipate making extraordinary material expenditures for environmental compliance during 2011. Total environmental expenditures for 2011 are expected to be approximately $4.5 million, which represents approximately 6% of the capital budget.
  Tax Horizon
  Compton has approximately $588.2 million in tax pools to apply against taxable income.  Based upon planned capital expenditure programs and current commodity price assumptions, it is anticipated the Corporation will not be cash taxable for a significant period of time.
  Capital Expenditures
  In 2010, Compton incurred approximately $46.3 million of capital costs in total (excluding asset retirement costs, acquisitions and divestitures): $6.7 million in exploration costs and $39.6 million in development costs.  In addition, approximately $23.5 million was received on overriding royalty dispositions and an additional $153.0 million was received from property dispositions.


- 37 -




Exploration and Development Activities




The following table sets forth the number of crude oil and natural gas wells drilled by the Corporation, or which the Corporation 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, 2010 and 2009.




Year Ended December 31, 2010

Year Ended December 31, 2009Development
Exploratory

Development
ExploratoryGross
Net
Gross
Net

Gross
Net
Gross
NetNatural gas
19
12
1
1

18
6
-
-Crude oil
2
1
-
-

2
1
-
-Service wells
-
-
-
-Standing wells(1)
1
-
4
3

-
-
-
-Dry and abandoned
3
2
1
1

-
-
-
-Total
25
15
6
5

20
7
-
-Success Ratio(2)
80%

96%


(1)
Standing wells are wells drilled and cased that have results pending.
 (2)
Excludes standing wells.





In 2011, the Corporation expects to continue to focus the majority of its resources in Alberta, Canada.  Compton’s overall objective for 2011 is to focus primarily on development activities and the advancement of reserves from the proved undeveloped and probable categories to the proved producing classification. Compton has plans for 2011 to help reinforce long-term strategies in its core areas. The development portfolio will be carefully monitored to live within cash flow and will be adjusted according to results. In 2011, Compton will focus on the liquids-rich, high return Niton area as well as its emerging oil opportunities in Southern Plains and Montana, providing significant upside potential through its multiple zone development opportunities and contiguous land blocks.




- 38 -




Production History




The Corporation’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

Three Months Ended


Year EndedMarch 31,

2010


June 30,

2010


September 30,

2010


December 31,

2010


December 31,

2010Natural gas (MMcf/d)


97



98



81



75



88Natural gas (MMcf)


8,734



8,957



7,440



6,867



31,999Natural gas liquids (boe/d)(2)


2,079



1,979



1,646



1,649



1,837Natural gas liquids (Mboe)(2)


187



180



151



152



670Crude oil (bbl/d)


1,158



1,096



807



762



954Crude oil (Mbbls)


104



100



74



70



348Total liquids (boe/d)


3,237



3,076



2,452



2,411



2,791Total liquids (Mboe)


291



280



226



222



1,019Total (boe/d)


19,411



19,481



15,931



14,852



17,402Total (Mboe)


1,747



1,773



1,466



1,366



6,352


(1)
Numbers may not add due to rounding.


(2)
Includes sulphur.






2011 Production Estimates




Company gross production volumes in 2011, as estimated in the Corporation’s reserve forecast from GLJ 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)ProvedDeveloped producing


600



69,759



1,166



167



13,393Developed non-producing


91



4,069



93



-



862Undeveloped


61



8,194



230



-



1,657Total proved


752



82,023



1,489



167



15,912Probable


32



4,367



105



1



865Total proved plus probable


785



86,390



1,594



167



16,777


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





Three Months Ended


Year EndedMarch 31,

2010


June 30,

2010


September 30,

2010


December 31,

2010


December 31,

2010Natural gas ($/Mcf)Price


4.38



5.67



4.15



3.84



4.43Royalties


0.9



(0.26
)


0.30



0.23



0.32Operating costs(1)


1.70



1.71



1.72



1.71



1.71Transportation costs


0.11



0.11



0.11



0.11



0.11Netback


1.58



4.11



2.02



1.79



2.29Natural gas liquids ($/bbl)(3)Price


61.68



60.61



52.19



66.28



60.29Royalties


14.49



15.39



15.28



24.63



17.21Operating costs(1)


10.18



10.27



10.30



10.25



10.25Transportation costs


1.75



3.14



7.01



1.39



3.23Netback


35.26



31.81



19.60



30.01



29.60Crude oil ($/bbl)Price


69.56



78.21



75.74



74.08



76.14Royalties


6.69



10.67



32.18



26.19



17.19Operating costs(1)


11.58



13.72



15.11



12.95



13.22Transportation costs


1.75



3.14



7.01



1.39



3.20Netback


49.54



50.68



21.44



33.55



42.53Total liquids ($/bbl)Price


67.59



66.00



59.39



69.30



65.71Royalties


11.70



13.71



20.84



25.12



17.20Operating costs(1)


10.68



11.50



11.88



11.11



11.26Transportation costs


1.75



3.14



7.01



1.39



3.22Netback


43.46



37.65



19.66



31.68



34.03Total ($/boe)Price(2)


40.79



32.38



29.66



32.14



34.02Royalties


6.89



0.86



4.75



5.23



4.36Operating costs(1)


10.27



10.46



10.54



10.39



10.41Transportation costs


0.86



1.07



1.65



0.79



1.09Netback


22.77



19.99



12.72



15.73



18.16


(1)
A portion of Compton’s natural gas production is associated with crude oil production; additionally the production of natural gas liquids is associated with natural gas production.  As a result, per unit operating costs for each product line reflect the allocation of certain common costs in this determination.


(2)
Includes third party processing fees, but not included in product pricing.


(3)
Includes sulphur.





- 40 -





The following table indicates average daily gross production from important areas in respect of Compton’s assets for the year ended December 31, 2010:





Area

Crude Oil

(Bbls/d)


Natural Gas

(Mcf/d)


Ngls

(Bbls/d)(3)


Total

(Boe/d)Niton(1)


582.2



26,356.4



968.7



5,943.6High River


9.0



20,754.9



424.8



3,892.9Southern Plains


332.1



31,290.0



331.5



5,878.7Foothills(2)


0.4



4,460.5



40.8



784.5Other


30.5



4,805.5



70.7



902.3Total


954.2



87,667.3



1,836.5



17,402.0


(1)
Includes Bigoray properties.


(2)
Callum, Cowley and Todd Creek properties.


(3)
Includes sulphur.






DIVIDENDS




The Corporation has neither declared nor paid any dividends on its Common Shares.  The Corporation 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 263,579,701 Common Shares are issued and outstanding as fully paid and non-assessable shares as at February 24, 2011.  No preferred shares are issued and outstanding as at February 24, 2011.  The Corporation also has 138,000,000 warrants outstanding, which are exercisable at $1.55 per share until October 5, 2011. The following is a description of the Corporation’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 Corporation 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 Corporation; (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 Corporation; and (iii) subject to the rights, privileges, restrictions, and conditions attached to any other class of shares of the Corporation, the holders of Common Shares are entitled to share equally in the remaining property of the Corporation upon liquidation, dissolution, or winding-up of the Corporation.




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





- 41 -





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.




Warrants




In October 2009, Compton completed an equity financing that included the issue of 138,000,000 Common Share purchase warrant. Each common share purchase warrant entitles the holder to acquire one additional Common Share at a price of $1.55 at any time prior to October 5, 2011.  Holders of warrants do not have rights as shareholders.




Stock Option Plan




Compton has a stock option plan (the “Stock Option Plan”) which offers the holders of Options the opportunity to participate in the appreciation of the Common Shares and is therefore intended to encourage employees (including executives) to improve the value of the Common Shares by achieving a high level of performance. Directors, Officers, employees and consultants of the Corporation and its subsidiaries are eligible to receive Options under the Stock Option Plan.




In accordance with the requirements of the Toronto Stock Exchange (the “TSX”), every three years after institution of a “rolling” stock option plan, all unallocated options, rights and other entitlements under such plan must be approved by both a majority of the issuer’s board of directors and a majority of the issuer’s shareholders. Compton’s Stock Option Plan is a rolling plan that was approved at the Corporation’s annual and special meeting of shareholders on May 12, 2010. The Corporation has the ability to continue granting options under the Stock Option Plan until 2013, which is three years from the date when shareholder approval was granted.




Shareholder Rights Plan




Compton has a shareholder rights plan (the “Rights Plan”) under the terms of a shareholder rights plan agreement dated as of June 3, 2009 between Compton and Computershare Trust Company of Canada, as rights agent. The Rights Plan is designed to encourage the fair treatment of shareholders in connection with a take-over bid for Compton. Rights issued under the Rights Plan become exercisable when a person, and any related parties, acquires or announces its intention to acquire 20% or more of the outstanding Common Shares without complying with certain provisions set out in the Rights Plan or without approval of the Board of Directors of Compton. Should such an acquisition or announcement occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase Common Shares at a 50% discount to the market price at that time. The Rights Plan was ratified by shareholders at the annual and special meeting of Compton shareholders held on May 11, 2009.




Shareholders may obtain a copy of the 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 500, 850 – 2nd Street S.W., Calgary, Alberta, Canada, T2P 0R8, Attention: Corporate Secretary.




- 42 -




MARKET FOR SECURITIES




The outstanding common shares of the Company are listed on the TSX under the symbol CMT. 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 Volume2010January

$
1.11


$
0.95



1,391,878February

$
0.98


$
0.88



543,961March

$
1.11


$
0.87



1,440,336April

$
1.02


$
0.93



470,747May

$
0.96


$
0.74



570,333June

$
0.81


$
0.60



1,225,573July

$
0.61


$
0.52



615,262August

$
0.51


$
0.39



639,384September

$
0.56


$
0.41



561,961October

$
0.55


$
0.475



390,729November

$
0.48


$
0.395



506,518December

$
0.445


$
0.395



862,7202011January

$
0.465


$
0.395



3,430,403$
0.445


$
0.42



1,566,813








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 Corporation.




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  that has not been resolved in the manner required by the ABCA.




- 43 -




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 Corporation, 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.




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:




·
a warrant indenture dated October 5, 2009 for 138,000,000 warrants, which are exercisable at $1.55 per share at any time during two years following the transaction’s close;




·
Compton’s senior credit facility of $170.0 million, arranged with a syndicate of banks, was comprised of a revolving term facility authorized at $155.0 million and a revolving working capital facility authorized at $15.0 million (see “General Development of the Business – Bank Debt and Senior Notes”);




·
an Indenture dated as of October 18, 2010, among Compton Petroleum Finance Corporation, as issuer, Compton, as parent guarantor, the subsidiary guarantors named therein, and The Bank of Nova Scotia Trust Company of New York, as trustee (the “Senior Note Indenture”), whereby, on October 18, 2011, Compton Petroleum Finance Corporation issued and sold U.S.$193.5 million aggregate principal amount of Senior Notes, which are unsecured and bear interest semi-annually, in arrears on December 1 and June 1 of each year, at a rate of 10% per year, with principal repayable on December 1, 2017.  The Senior Notes are guaranteed by Compton;




·
an Indenture dated as of October 18, 2010, among Compton Petroleum Finance Corporation, as issuer, Compton, as parent guarantor, the subsidiary guarantors named therein, and The Bank of




- 44 -




·
Nova Scotia Trust Company of New York, as trustee (the “Mandatory Convertible Note Indenture”), whereby, on October 18, 2011, Compton Petroleum Finance Corporation issued and sold U.S.$45 million aggregate principal amount of Mandatory Convertible Notes due September 2011, which are unsecured and bear interest at a rate of 10% per year.  The Mandatory Convertible Notes are guaranteed by Compton; and




·
a purchase and sale and royalty agreement for the sale of an overriding royalty (“ORR”) to a third party. The ORR represents 5.0% of the gross production revenue on the Corporation’s existing land base less certain transportation costs and marketing fees, calculated on a monthly basis.






LEGAL PROCEEDINGS AND REGULATORY ACTIONS




To the knowledge of the Corporation, there are no legal proceedings material to the Corporation to which the Corporation 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, 2010 nor are there any such proceedings known to the Corporation to be contemplated.




During the year ended December 31, 2010, there were no: (i) penalties or sanctions imposed against the Corporation 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 Corporation that would likely be considered important to a reasonable investor in making an investment decision, or (iii) settlement agreements the Corporation entered into before a court relating to securities legislation or with a securities regulatory authority.




INTERESTS OF EXPERTS




As at the date hereof, the partners and associates of Grant Thornton, LLP, the auditors of Compton, as a group, did not beneficially own any of Compton’s outstanding Common Shares. As at the date hereof, principals of GLJ, the independent reserve auditors of Compton, as a group, own, directly or indirectly, less than 1% of the outstanding Common Shares.




RATINGS




Standard & Poor’s Rating Services (“S&P”) and Moody’s Corporation (“Moody’s”) have not rated Compton Petroleum Corporation’s U.S. $193.5 million 10% Senior Notes due 2017 or U.S. $45.0 million 10% Mandatory Convertible Notes due September 2011 as at December 31, 2010.  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. S&P and Moody’s did rate the previously issued U.S. $450 million 75⁄8% senior notes as B and Caa1 respectively, as at December 31, 2009, which was discontinued after the Arrangement and recapitalization of the Corporation’s capital structure in October 2011.




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




- 45 -




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




The next Annual Meeting is scheduled for May 10, 2011 at 3:30 p.m. (Calgary time) in the ENMAX Ballroom on the Fourth Floor of the Calgary Chamber of Commerce, 517 Centre Street South, Calgary, Alberta, Canada. All directors of Compton stand for election at each annual meeting of the Corporation.




The Board of Directors has established an Audit, Finance and Risk Committee; Reserves, Operations and Environmental, Health and Safety Committee; and a Corporate Governance, Human Resources and Compensation Committee.  The Board Committees are comprised of independent directors, other than Mr. Granger who is an ex-officio non-voting member of the Reserves, Operations and Environmental, Health & Safety Committee and the Corporate Governance, Human Resources and Compensation Committee. Mr. Granger is a non-independent director due to his position as President & Chief Executive Officer of Compton.




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




Name and Municipality of Residence

Principal Occupation

Director

SinceMel F. Belich, Q.C.

Calgary, AB, Canadá

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.

1993J. 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 40 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.Mr. Allan is the Chairman of the Audit, Finance and Risk Committee.

2007





- 46 -





Name and Municipality of Residence

Principal Occupation

Director

SinceDavid 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 Trust (“PrimeWest”), an oil and gas royalty trust). Mr. Fitzpatrick has served as a Director of PrimeWest, Shiningbank Energy Income Fund, Platform Energy, Fairquest Energy, Eagle Energy Trust, Pinecrest Energy Ltd. and Twin Butte Energy Ltd., each of which is or was an oil and gas company or trust.

2009Tim Granger, P.Eng.,

Calgary, AB, Canada

President & Chief Executive Officer of the Corporation.  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 by TAQA in January of 2008.  Prior to such acquisition Mr. Granger had served as the Chief Operating Officer of PrimeWest since 1999.

2009R. Bradley 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., Direct Cash Payments Inc.  and serves on the Advisory Board of Marsh Canada.

2009Irvine 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 Executive Vice President and President and Chief Executive Officer, 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 and Chairman of NAL Energy Corporation, a public oil and gas company.

Mr. Koop is the Chairman of the Corporate Governance, Human Resources and Compensation Committee.

1996Warren M. Shimmerlik

Bedford, New York, United States

Independent businessman. Previously, he was a Member and Principal of COSCO Capital Management LLC, a private equity intermediary. Mr. Shimmerlik spent nearly two decades as a highly regarded Wall Street Energy Analyst, holding senior positions at Merrill Lynch & Company, L. F. Rothschild Unterberg Towbin and County NatWest Securities USA.

2009Jeffrey 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 Ltd. and Pace Oil and Gas, each an oil and gas company.

Mr. Smith is Chairman of the Reserves, Operations and Environmental, Health and Safety Committee.

1999




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Further information about the directors and the committees of the Board of Directors is set forth under the heading “Election of Directors” in the Corporation’s Management Proxy Circular dated February 24, 2011 relating to the Meeting to be held on May 10, 2011, which sections are incorporated by reference into this AIF.




Officers




Information is given below with respect to each of the current officers of the Corporation.  The name, city of residence, and principal occupation during the last five years of each of the officers of the Corporation are set forth in the following table.




Name and Municipality of Residence

Principal OccupationTim Granger, P. Eng.

Calgary, Alberta

President & Chief Executive Officer of the Corporation.  Mr. Granger has more than 27 years of experience in the petroleum industry which includes extensive experience in exploitation and production operations.  Mr. Granger previously served as Vice President, Asset Optimization and Chief Operating Officer at Paramount Energy Trust, a natural gas royalty trust, and prior to that Mr. Granger was Managing Director TAQA North, an oil and gas exploration company, following the acquisition of PrimeWest 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.C.W. Leigh Cassidy, CA, CFA

Calgary, Alberta

Vice President, Finance & Chief Financial Officer of the Corporation. Mr. Cassidy brings more than 20 years of senior financial experience in the petroleum industry which includes extensive restructuring, capital and debt market experience. Most recently, Mr. Cassidy was Chief Financial Officer at Bow Valley Energy and prior to that, held various senior positions at Signet Energy, UTS Energy, Household International, Emtech and Procter and Gamble.David B. Horn, BA Econ.

Calgary, Alberta

Vice President, Business Development & Land of the Corporation. Mr. Horn’s career spans over 26 years of acquisition and divestiture and land experience in the petroleum industry, having executed over $5 billion in corporate and asset acquisitions and divestitures during this time. Most recently, he was President of The Oil and Gas Asset Clearinghouse, managing the company’s Calgary office.Shannon L. Ouellette, M. Eng., P. Eng.

Calgary, Alberta

Chief Operating Officer of the Corporation. Ms. Ouellette brings extensive experience in operations and asset development through her 18 years experience in the petroleum industry. Previously, she was Vice President, Operations at TAQA North Ltd. where she managed all field operations and played a leading role in integrating the TAQA North and PrimeWest assets. Her operational experience also includes managing the PrimeWest and Shiningbank Energy Income Fund assets post merger.





As at February 24, 2011, the directors and officers of Compton as a group beneficially owned or controlled, directly or indirectly, 4.9 million Common Shares of Compton, representing approximately 2% of the issued and outstanding Common Shares of the Corporation.  None of the directors or officers held a sufficient number of Common Shares to materially affect the control of Compton.







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COMMITTEE INFORMATION




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 Corporation’s website.  The Board affirmatively determines on an annual basis the independence of its members.  Messrs. Allan, Belich, Fitzpatrick, Hurtubise, Koop, Shimmerlik, and Smith have been determined to be independent directors.




Audit, Finance and Risk Committee




Chairman:
J. Stephens Allan


Members:
R. Bradley Hurtubise, Warren M. Shimmerlik, Mel F. Belich (ex officio, voting)




Mr. Allan 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 corporate finance and accounting as a Chartered Accountant and Financial Analyst.  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.




The Charter of the Audit, Finance and Risk Committee can be located on the Corporation’s website at www.comptonpetroleum.com.




External Auditor Fees




The aggregate amounts billed by Grant Thornton LLP to the Corporation with respect to fees payable 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, 2010 and 2009 were as follows:




Type of Service
Fiscal 2010
Fiscal 2009Financial statement and internal controls audit
$     754,218
$ 1,030,849Audit related
125,007
51,636Tax
22,601
21,945Other non-audit
151,543
137,000Total
$  1,053,369
$ 1,241,430




Financial statement audit fees in fiscal 2010 and 2009 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 2010 and 2009 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.




Tax services performed by Grant Thornton outside of normal audit procedures during 2010 related to debt restructuring and the preparation and filing of the annual returns.  Other non-audit fees relate to services provided during the issue of offering documents as well as the preparation of a scoping, planning and




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implementation document to support the Corporation’s transition to International Financial Reporting Standards on January 1, 2011.




The Audit, Finance and Risk Committee of the Corporation considered these fees and determined that they were reasonable and do not impact the independence of the Corporation’s auditors.  Further, such Committee determined that in order to ensure the continued independence of the auditors, only limited non-audit related services would be provided to the Corporation 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.




Reserves, Operations and Environmental, Health and Safety Committee




Chairman:
Jeffery T. Smith


Members:
David Fitzpatrick, Irvine J. Koop, Mel F. Belich (ex officio, voting), Tim Granger (ex officio, non-voting)




The Charter of the Reserves, Operations and Environmental, Health and Safety Committee can be located on the Corporation’s website at www.comptonpetroleum.com.




Corporate Governance, Human Resources and Compensation Committee




Chairman:
Irvine J. Koop


Members:
J. Stephens Allan, Jeffrey T. Smith, Mel F. Belich (ex officio, voting), Tim Granger (ex, officio, non-voting)




The Charter of the Corporate Governance, Human Resources and Compensation Committee can be located on the Corporation’s website at www.comptonpetroleum.com.





TRANSFER AGENT AND REGISTRAR




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





ADDITIONAL INFORMATION




Additional information including directors’ and officers’ remuneration, principal holders of the Corporation’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 February 24, 2011, relating to the Annual and Special Meeting of Shareholders to be held on May 10, 2011.  Additional financial information is also provided in the consolidated financial statements and Management’s Discussion and Analysis of the Corporation for the year ended December 31, 2010, included in the Corporation’s 2010 Annual Report.  Copies of these and other documents relating to Compton have been filed with the System for Electronic Document Analysis and Retrieval (“SEDAR”) at www.sedar.com. Copies of the AIF may be obtained on request without charge by contacting:




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Compton Petroleum Corporation


Suite 500 Bankers Court


850 – 2nd Street S.W.


Calgary, Alberta, Canada


T2P 0R8


Attention:
Corporate Secretary


Telephone:
(403) 237-9400


Fax:
(403) 237-9410




In addition to the continuous disclosure obligations under the securities laws of the provinces of Canada, Compton is subject to the information reporting requirements of the Exchange Act, and in accordance therewith file reports with, and furnish other information to, the SEC. Under a multi-jurisdictional disclosure system adopted by the United States and Canada, these reports and other information (including financial information) may be prepared in accordance with the disclosure requirements of Canada, which differ in certain respects from those in the United States. As a foreign private issuer, the Corporation is exempt from the rules under the Exchange Act prescribing the furnishing and content of proxy statements, and Compton’s officers, directors and principal shareholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, Compton is not required to publish financial statements as promptly as U.S. companies.




Any document filed with or furnished to the securities commissions and authorities of the provinces of Canada may be read through SEDAR. Any document filed with or furnished to the SEC may be read at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Prospective investors may call the SEC at 1-800-SEC-0330 for further information regarding the public reference facilities. The SEC also maintains a website at www.sec.gov that contains reports and other information Compton files with the SEC.




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.  Compton has used the 6:1 boe measure in this document, 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 Corporation contained herein include “forward-looking information” and “forward-looking statements” within the meaning of applicable Canadian securities laws, and “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995 and the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”).




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Forward-looking information and statements involve risks, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied by them. Sentences and phrases containing words such as “believe”, “estimate”, “anticipate”, “plan”, “predict”, “outlook”, “goals”, “targets”, “projects”, “may”, “hope”, “can”, “will”, “should”, “expect”, “intend”, “is designed to”, “continues”, “with the intent”, “potential”, “strategy”, and the negative of any of these words, or variations of them, or comparable terminology that does not relate strictly to current or historical facts, are all indicative of forward-looking information or statements. Discussions containing forward-looking statements may be found, among other places, in the “General Development of the Business”, “Description of the Business” and “Risk Factors” sections herein. Examples of forward-looking information and statements in this AIF include, but are not limited to:




·
the focus of capital expenditures;




·
the sale, farming in, farming out or development of certain exploration properties using third party resources;




·
the impact of changes in oil and natural gas prices on cash flow after hedging;




·
drilling plans;




·
the existence, operation and strategy of the commodity price risk management program;




·
the approximate and maximum amount of forward sales and hedging to be employed;




·
Compton’s growth strategy, the criteria to be considered in connection therefore and the benefits to be derived there from;




·
the impact of Canadian federal and provincial governmental regulation on Compton relative to other oil and gas issuers of similar size;




·
the goal to sustain or grow production and reserves through prudent management and acquisitions;




·
the emergence of accretive growth opportunities; and




·
Compton’s ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets.




The material assumptions in making these forward-looking statements include certain assumptions disclosed in Compton’s annual Management's Discussion and Analysis under the headings “Liquidity and Capital Resources”, “Capital Structure”, “Outlook” and “Critical Accounting Estimates”.
 
 Although Compton believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct.  There is no guarantee of future results, levels of activity, performance, or achievements. Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below, elsewhere in this AIF and in Compton’s annual Management’s Discussion and Analysis under the heading “Risks”, including, but not limited to:




·
general economic conditions in Canada, the United States and globally;




·
industry conditions, including volatility in market prices for oil and natural gas;




·
royalties payable in respect of Compton’s oil and natural gas production;




·
governmental regulation of the oil and gas industry, including environmental regulation;




·
fluctuation in foreign exchange or interest rates;




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·
unanticipated operating events which can reduce production or cause production to be shut in or delayed or operating costs to increase;




·
failure to obtain industry partner and other third party consents and approvals, when required;




·
stock market volatility and market valuations; and




·
the need to obtain required approvals from regulatory authorities.




Statements relating to “reserves” or “resources” are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this AIF:




(a)
were made as of the dates stated therein;




(b)
represent Compton’s views as of such dates and should not be relied upon as representing its views as of any subsequent date; and




(c)
are expressly qualified by this cautionary statement.




While Compton anticipates that subsequent events and developments may cause its views to change, the Corporation specifically disclaims any intention or obligation to update forward-looking information and statements, whether as a result of new information, future events or otherwise, except to the extent required by applicable securities laws. Except as required by law, Compton has no obligation to update or revise any forward-looking information or forward-looking statement, whether as a result of new information, future events or otherwise.




Forward-looking information and statements contained in this AIF by reference about prospective results of operations, financial position or cash flows that are based upon assumptions about future economic conditions and courses of action are presented for the purpose of assisting the Corporation’s security holders in understanding Management’s current views regarding those future outcomes, and may not be appropriate for other purposes.




There can be no assurance that the forward-looking information and statements will prove to be accurate, and actual results and future events could vary or differ materially from those anticipated by them. Accordingly, undue reliance should not be placed on forward-looking information and statements. Forward-looking information and statements for time periods subsequent to 2011 involve greater risks and require longer term assumptions and estimates from those for 2011, and are consequently subject to greater uncertainty. Therefore, special caution should be taken in terms of placing reliance on such long-term forward-looking information and statements.




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SCHEDULE A


REPORT ON RESERVES DATA BY INDEPENDENT


QUALIFIED RESERVES


EVALUATOR OR AUDITOR










- 54 -










- 55 -




SCHEDULE B


REPORT OF MANAGEMENT AND DIRECTORS


ON RESERVES ON OIL AND GAS DISCLOSURE







Management of Compton Petroleum Corporation (the “Corporation”) is responsible for the preparation and disclosure of information with respect to the Corporation’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, 2010, estimated using forecast prices and costs.




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




The Reserves, Operations and Environmental, Health and Safety Committee of the Board of Directors of the Corporation has:




(a)
reviewed the Corporation’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 Reserves, Operations and Environmental, Health and Safety Committee of the Board of Directors has reviewed the Corporation’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 Reserves, Operations and Environmental, Health and Safety 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.




/s/ Tim Granger

Tim Granger

President & CEO
/s/ Shannon Ouellette

Shannon Ouellette

Chief Operating Officer/s/ Jeffrey Smith

Jeffrey Smith

Chairman of the Reserves, Operations & Environmental,

Health and Safety Committee
/s/ Mel Belich

Mel Belich

Chairman of the Board







February 24, 2011