ex201.htm

EX-20.1 2 ex201.htm ANNUAL INFORMATION FORM FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009 ex201.htm

Exhibit 20.1

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2009

FEBRUARY 25, 2010

	Page

ABBREVIATIONS AND CONVERSION FACTORS	2
DEFINITIONS	3
CORPORATE STRUCTURE	9
GENERAL DEVELOPMENT OF THE BUSINESS	10
DESCRIPTION OF THE BUSINESS	11
RISK FACTORS	17
STATEMENT OF RESERVES DATA	23
DIVIDENDS	37
CAPITAL STRUCTURE	37
MARKET FOR SECURITIES	39
CONFLICTS OF INTEREST	39
INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	40
CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS	40
MATERIAL CONTRACTS	40
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	41
INTERESTS OF EXPERTS	41
RATINGS	41
DIRECTORS AND OFFICERS	42
COMMITTEE INFORMATION	45
TRANSFER AGENT AND REGISTRAR	47
ADDITIONAL INFORMATION	47
ADVISORIES	48

SCHEDULE A REPORT ON RESERVES DATA	51
SCHEDULE B REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES ON OIL AND GAS DISCLOSURE	53

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;

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

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

“km2” means square kilometres;

“lt” means long ton;

“Mbbls” means thousand barrels;

“Mboe” means thousand barrels of crude oil equivalent;

“Mcf” means thousand cubic feet;

“Mcfe” means thousand cubic feet equivalent;

“mi” means miles;

“mi2” means square miles;

“Mlt” means thousands of long tons;

“MMbbls” means million barrels;

“MMBoe” means million barrels of crude oil equivalent;

“MMbtu” means million British thermal units;

“MMcf” means million cubic feet;

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

“MMcfe” means million cubic feet equivalent; and

“ngls” means natural gas liquids.

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Conversion Factors

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

To Convert From	To	Multiply By
boe	Mcfe	6.000
cubic feet	cubic metres of gas	0.028
cubic metres of gas	cubic feet	35.490
bbls of oil	cubic metres	0.159
cubic metres	bbls of oil	6.289
gigajoule	thousand cubic feet of natural gas	0.95
feet	metres	0.305
metres	feet	3.281
miles	kilometres	1.609
kilometres	miles	0.621
acres	hectares	0.400
hectares	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 Canadian dollar in exchange for U.S. dollars using information provided by the Bank of Canada.

	Year Ended December 31,
	2009		2008
High	$	1.3000	$	1.0289
Low	$	1.0292	$	0.7711
Average	$	1.1420	$	0.9441
Year-End	$	1.0466	$	0.8166

The noon exchange rate on December 31, 2009, using information provided by the Bank of Canada for the conversion of Canadian dollars into United States dollars, was $1.00 equals US$0.9555.

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 partnership and subsidiaries where the context so requires.

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

“Deep Basin” means the area situated along the northeastern 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

(d)

provide improved recovery systems.

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“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 likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

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“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

(c)

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

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“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.

The Corporation’s head and principal office is located at Suite 500, 850 - 2nd Street S.W., Calgary, Alberta, Canada, T2P 0R8. Compton’s registered office is located at Suite 4300 Bankers Hall West, 888 - 3rd Street, S.W., Calgary, Alberta, Canada, T2P 5C5.

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

Compton Petroleum Finance Corporation, formed under the laws of Alberta, is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Petroleum Finance Corporation has no independent operations and has no significant liabilities or assets other than US$450 million of 7⅝% Senior Notes issued by Compton Petroleum Finance Corporation, its equity interest in Hornet Energy Ltd. and intercorporate indebtedness. The registered office of Compton Petroleum Finance Corporation is 4300 Bankers Hall West, 888 - 3rd Street S.W., Calgary, Alberta, Canada, T2P 5C5.

Compton Petroleum Holdings Corporation, formed under the laws of Alberta, is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Petroleum Holdings Corporation has no independent operations and has no significant liabilities or assets. The registered office of Compton Petroleum Holdings 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 and partnerships.

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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 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 three Deep Basin natural gas plays: the Gething/Rock Creek sands at Niton and Gilby in central Alberta, the Basal Quartz sands at High River in southern Alberta, and the shallower Plains Belly River sand play in southern Alberta. In addition, the Corporation has an 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 commenced operations in 1993 with $1 million of share capital and has since increased its natural gas portfolio, which currently represents approximately 84% of reserves and production. Compton’s shares are listed on the Toronto Stock Exchange under the symbol CMT and on the New York Stock Exchange under the symbol CMZ.

Three Year History

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

In 2008, activities were directed towards the continued development of the 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 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.

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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 providing 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 provides 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 was 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.

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. This will be achieved through the evaluation of the benefits of various opportunities and pursuit of those that provide the optimal return, maximizing cash flow and asset value. Compton has experienced professional, management, technical, and support staff sufficient to carry out its business plan and its current exploration, exploitation, development, production, engineering, financial, and administrative functions.

The 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 is in the process of completing a robust multi-year plan that will provide a strategic direction and plan for future value creation.

Implement Measured and Flexible Financial Approach. Compton will take a flexible financial approach, adjusting its 2010 capital spending up or down, depending upon how economic circumstances unfold during the year, and intends to limit capital expenditures to within cash flow. 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.

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Focus on Unconventional Natural Gas in Large Resource Plays. The Corporation has gained considerable technical expertise and achieved significant success in exploring for unconventional, larger natural gas accumulations in the WCSB. Compton plans to continue to focus on finding and developing these large scale types of natural gas opportunities because of their generally longer life and lower exploration risk compared to conventional natural gas opportunities. In addition, the Corporation’s areas of large contiguous land provide economies of scale for development, increasing return on capital.

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. The Corporation 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 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 three Deep Basin development gas plays: the Gething/Rock Creek sands at Niton and Gilby in central Alberta, the Basal Quartz sands at High River in southern Alberta, and the shallower Plains Belly River sand play in southern Alberta. In addition, the Corporation has one exploratory play in the Foothills area of southern Alberta, which is a thrusted over-pressured Belly River sand formation at Callum/Cowley/Todd Creek. These areas are the geographic focus of Compton’s seismic database and are areas in which Management and staff have significant technical expertise and operational experience.

Development Properties

Niton and Gilby (Central Alberta)

The Niton and Gilby areas are multi-zone liquids rich, tight gas plays with production primarily coming from Jurassic Rock Creek, and Mannville Ellerslie/Gething sands. Proprietary exploration, development, and operational knowledge gained by the Corporation in southern Alberta has resulted in development of this core area. Compton has drilled over 175 wells to date on its 245 gross sections of controlled land in this area, where it has a 75% working interest.

The Rock Creek play’s variable permeability and water-free nature lends itself well to horizontal drilling and multistage fracturing. Compton is the leading Niton operator developing this play with 30 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.

In 2009, Compton experienced solid drilling success, drilling one vertical and four horizontal wells targeting the Rock Creek formation in Niton and participating in an additional eight non-operated horizontal and vertical wells at Niton and Gilby.

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In 2010, Compton will continue its development of the Rock Creek formation at Niton. 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 operators either vertically and horizontally. Compton intends to continue technical work to understand these other uphole zones and begin testing select zones above the Rock Creek in Gilby using horizontal drilling with multi-stage fracturing. This evaluation and testing may lead to new drilling programs in the future, supplementing the growth potential from the Rock Creek formation.

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 90 gross sections with an average 85% working interest in this area that is prospective for the Basal Quartz Pool. This pool has cumulative production of 123 BCF. In 2009, the pool produced 27.1 MMcf/d from the Basal quartz formation in 111 wells over five townships. With an annual pool wide base decline of 14%, the pool is a legacy 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 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. Data gained from these wells was invaluable for future development. A key component of success in this area will be to minimize drilling and completion costs. Compton is in the process of meshing the engineering and geological data to better understand the unexploited parts of the reservoir and target horizontal wells in this formation. Management is also focused on refining the drilling and fracture design, and applying the knowledge gained through horizontal drilling to increase operational efficiencies and economics. Once this is achieved, High River is expected to become a very active area for the Corporation.

Additionally, Compton is reviewing the potential to re-enter existing wellbores and refracture the Basal Quartz Formation. 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. In 2010, the Corporation is going to test this process with some of its existing vertical wells. If successful, there remains over 100 existing producing vertical wells at High River that will be evaluated for refracturing.

Plains Belly River and Edmonton Group (Southern Alberta)

The Plains Belly River 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.

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Compton has over one hundred low risk development locations surveyed and licensed in the Plains Belly River and Edmonton Group. With control of 1,000 gross sections of land at an average 90% working interest, this land base provides a significant multi-year, low risk drilling inventory at two to four wells per section.

In 2009 Compton participated in six gross development wells from the Ghost Pine Unit. At year-end, the Corporation was producing 37.1 MMcf/d from 732 wells in the Plains Belly River area. Ample infrastructure is in place in the area for future production increases with 32,500 horsepower of compression and approximately 1,300 kilometres of pipeline.

In 2010, Compton will further analyze the reservoir, using selective drilling to high-grade drill locations. There is significant potential to reduce operating costs and optimize operations in this area, which will further improve the economics of the play. In addition, there may be an opportunity to develop deeper zones below the Belly River that the Corporation has not yet exploited. During 2010, Compton plans to assess the potential of these horizons by using the knowledge gained through its extensive land and seismic database.

Exploratory Properties

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

Compton controls 157 gross sections at an average 87% working interest in the Foothills area of southern Alberta, and has drilled 37 wells to date, 26 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 spots with these fractures, which is crucial to better access natural gas flows and increase the economics of the play. While there is a lot of data in the area from well cores, additional geochemical work is being done to determine placement of the gas, characteristics of the rock and proper extraction techniques.

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.

Principal Markets and Distribution

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.

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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 into 2010.

Environmental Policies

Compton expects excellence in health, safety and environmental performance. The Corporation is committed to conducting all operations in a safe manner that minimizes environmental impact, while meeting regulatory requirements and corporate standards. The Corporation 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. The Corporation’s proactive program includes annual environmental compliance audit and inspection programs to ensure Compton’s facilities continually meet or exceed regulatory standards. The Corporation 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 Compton’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. At present, the Corporation believes that it meets all existing environmental standards and regulations and has included appropriate amounts in its 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 2010. However, it 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 in accordance with Canadian generally accepted accounting principles. The quantitative assessment along with qualitative discussion in respect to environmental protection requirements, policies and costs can be found in “Statement of Reserves Data - Additional Information Concerning Abandonment and Reclamation Costs” in this AIF.

Mazeppa Processing Partnership

In June of 2003, Mazeppa Processing Partnership (“MPP”) acquired certain midstream assets from an independent third party. The assets consist of major natural gas gathering and processing facilities in Southern Alberta. Compton does not have an ownership position in MPP. 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.

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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 Partnership 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, the Corporation 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 Term Notes

Compton’s outstanding bank debt at December 31, 2009 of $107.0 million was drawn on a revolving term facility authorized at $190.0 million and a revolving working capital facility authorized at $30.0 million (for a total of $220.0 million - together the “Credit Facilities”). As of the date of the AIF, the Credit Facilities were reduced to a total of $217.5 million following the exercised overriding royalty options subsequent to year-end. The Credit Facilities were renewed on July 2, 2009 for a period of 364 days until July 1, 2010. The Corporation expects that the Credit Facilities will be renewed at that time for a further 364-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 Facility provides 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 Facility is secured by a fixed and floating charge debenture on the assets of the Corporation.

The indenture governing the senior term notes (the “Note Indenture”) limits 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 fixed charge coverage ratio must exceed a trailing four quarters 2.5 to 1 threshold and if the Ratio is less than 2.5 to 1, the value calculated under the ACNTA test must exceed borrowings under the Credit Facilities. The Ratio restricts Compton’s ability to incur incremental debt, and the value determined under the ACNTA test restricts the borrowings under the Credit Facilities to the ACNTA calculated value.

At December 31, 2009, the Ratio was 2.0 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 $263.4 million under the Credit Facility 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.

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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 2010.

Employees

As at December 31, 2009, Compton had 123 full-time employees in its Calgary office and 58 full-time employees at field locations.

Competitive Conditions

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

RISK FACTORS

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 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.

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Liquidity Risk

Liquidity risk is the risk that the Corporation is not able to meet its financial obligations as they fall due. Compton’s $210.0 million term Credit Facilities come due in July 2010 unless renewed by that time. 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. As at December 31, 2009, Compton had $107.0 million outstanding under its Credit Facilities.

In addition, both the Credit Facilities and the Note Indenture governing the US$450 million of 7.625% senior notes due in 2013 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 restricts Compton from incurring new debt. The value determined under the ACNTA test limits borrowings under the Credit Facilities to the ACNTA calculated value. At December 31, 2009, the fixed charge coverage test resulted in a ratio of 2.0 to 1 (5.35 to 1 at December 31, 2008). The December 31, 2009 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 $263.4 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 affect on the operations of the Corporation.

The calculation of the ACNTA was $263.4 million at December 31, 2009 ($383.0 million at December 31, 2008), 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.

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.

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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 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.

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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 there from, 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 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, it is likely that significant differences will 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.

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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, 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.

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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 $13.19 and $7.40 in 2007; $13.20 and $0.88 in 2008; and $2.03 and $0.56 in 2009, respectively.

The high and low closing sale prices of Common Shares on the NYSE were US$12.16 and US$7.70 in 2007; US$12.94 and US$0.68 in 2008; and US$1.75 and US$0.44 in 2009, 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 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 implements 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 be providing companies with a one-time option to select new transitional royalty rates, on a well-by-well basis, to companies that are drilling new natural gas or conventional oil wells (between 1,000 and 3,500 metres deep) after January 1, 2009. All wells that are drilled between 2009 and the end of 2013 that adopt the transitional rates will be required to shift to the New Royalty Framework on January 1, 2014. All current wells moved to the New Royalty Framework on January 1, 2009.

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

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Environmental Risks

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. 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.

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.

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.

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.

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.

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, 2009, prepared by the independent international integrated petroleum engineering and geological firm, Netherland, Sewell & Associates, Inc. (“Netherland Sewell”). 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 Netherland Sewell’s opinions of reasonable practice in the industry.

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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 25, 2010. The information being provided in this statement has an effective date of December 31, 2009 and a preparation date of February 3, 2010.

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

Forecast Prices and Costs

A summary of the 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, 2009

	Crude Oil				Natural Gas(2)				Ngls				Sulphur				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Reserves Category (1)	(Mbbl)		(Mbbl)		(MMcf)		(MMcf)		(Mbbl)		(Mbbl)		(Mlt)		(Mlt)		(Mboe)		(Mboe)
Proved
Developed producing		3,688		2,650		370,386		301,962		7,184		4,466		1,770		1,501		74,372		58,944
Developed non-producing		37		30		35,502		29,187		449		270		56		44		6,459		5,208
Undeveloped		54		44		90,656		71,881		1,633		1,014		141		112		16,937		13,150
Total proved		3,779		2,724		496,544		403,030		9,266		5,750		1,966		1,657		97,768		77,302
Probable		2,808		1,770		340,388		264,223		6,174		3,751		862		697		66,575		50,255
Total proved plus probable		6,587		4,494		836,932		667,253		15,440		9,500		2,828		2,354		164,343		127,557

(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.

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The tables set forth below summarize the Corporation’s future net revenue as of December 31, 2009, based on forecast prices and cost assumptions.

Summary of Future Net Revenue as of December 31, 2009 (Forecast Prices)

	Future Net Revenue ($000s) Before Income Taxes Discounted at (%/year)
Reserves Category (1)		0%	5%	10%	15%	20%
Proved
Developed producing		2,417,721	1,322,461	915,989	711,953	589,134
Developed non-producing		208,483	126,068	86,224	63,808	49,777
Undeveloped		388,983	212,333	125,285	77,757	49,410
Total proved		3,015,186	1,660,862	1,127,499	853,518	688,321
Probable		1,840,044	951,908	567,018	368,029	252,588
Total proved plus probable		4,855,230	2,612,770	1,694,516	1,221,547	940,909

(1)	Numbers may not add due to rounding.

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

	Future Net Revenue ($000s) After Income Taxes Discounted at (%/year)
Reserves Category (1)		0%	5%	10%	15%	20%
Proved
Developed producing		2,045,008	1,227,636	846,620	681,021	567,867
Developed non-producing		178,485	111,319	79,335	59,237	47,153
Undeveloped		320,868	174,414	109,381	65,409	41,958
Total proved		2,544,362	1,513,369	1,035,337	805,668	656,978
Probable		1,380,106	713,454	425,940	270,302	185,446
Total proved plus probable		3,924,468	2,226,823	1,461,277	1,075,970	842,425

(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, 2009 (Forecast Prices)

Reserves Category(1)	Revenue		Royalties		Operating Costs		Development Costs		Well Abandonment Costs(2)		Future Net Revenue Before Income Taxes		Income Taxes		Future Net Revenue After Income Taxes
	($000s)		($000s)		($000s)		($000s)		($000s)		($000s)		($000s)		($000s)
Proved		6,689,212		1,425,952		2,044,513		152,668		50,892		3,015,186		470,824		2,544,362
Proved plus probable		11,198,504		2,581,799		3,108,127		587,190		66,157		4,855,230		930,763		3,924,468

(1)	Numbers may not add due to rounding.

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

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The following table summarizes the Corporation’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, 2009 (Forecast Prices)

Reserves Category	Production Group	Future Net Revenue Before Income Taxes (discounted at 10%/year) ($000s)		Unit Value(3) ($/bbl - $/Mcf)
Proved	Crude oil(1)		164,312		60.32
	Natural gas and ngls(2)		963,187		2.45
	Total		1,127,499
Proved plus probable	Crude oil(1)		241,694		53.78
	Natural gas and ngls(2)		1,452,822		2.23
	Total		1,694,516

(1)	Includes solution gas and related ngls.

(2)	Excludes solution gas and related ngls.

(3)	Unit values are based on net reserves.

Pricing Assumptions

Future net revenue calculated using forecast prices and costs is based upon the price assumptions set out below. Netherland Sewell incorporated price forecasts which were the average of the December 31, 2009 pricing forecasts prepared by four major Canadian consulting firms in estimating Compton’s reserves data using forecast pricing and costs.

Summary of Forecast Pricing and Inflation Rate Assumptions as of December 31, 2009

	Crude Oil				Natural Gas				NGLS				Sulphur		Inflation Rate(1)		Exchange Rate
Year	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		$Cdn/$US
Forecast
2010		78.54		82.06		5.79		48.56		62.45		84.47		22.95		2.00%		0.94
2011		83.17		86.96		6.61		51.68		66.18		89.49		28.38		2.00%		0.94
2012		86.54		90.52		6.88		53.83		68.91		93.17		40.73		2.00%		0.94
2013		90.18		94.35		7.27		56.08		71.84		97.09		46.34		2.00%		0.94
2014		94.18		98.57		7.60		58.54		75.12		101.45		55.71		2.00%		0.94
2015		98.00		102.58		7.80		60.84		78.23		105.58		57.11		2.00%		0.94
2016		101.36		106.12		8.02		62.90		80.98		109.28		58.53		2.00%		0.94
2017		103.38		108.26		8.32		64.17		82.61		111.45		59.99		2.00%		0.94
2018		105.43		110.42		8.62		65.46		84.28		113.68		61.47		2.00%		0.94
2019		107.57		112.65		8.84		66.78		85.97		115.99		62.74		2.00%		0.94
2020		109.71		114.91		9.04		68.13		87.69		118.30		64.00		2.00%		0.94
There-after		2.0%		2.0%		2.0%		2.0%		2.0%		2.0%		2.0%		2.00%		0.94

(1)	Inflation rate for operating and capital costs.

The weighted average realized sales price for Compton for the year ended December 31, 2009 was $4.16/Mcf for natural gas, $61.51/bbl for crude oil, $47.29/bbl for ngls, and $26.67/lt for sulphur.

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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 Gas
	Gross Proved (Mbbl)			Gross Probable (Mbbl)			Gross Proved Plus Probable (Mbbl)			Gross Proved (MMcf)			Gross Probable (MMcf)			Gross Proved Plus Probable (MMcfl)
December 31, 2008		4,786			3,156			7,942			640,396			479,013			1,119,409
Extensions		(73	)		85			12			3,520			6,834			10,354
Improved recovery		-			-			-			-			-			-
Technical revisions		67			(281	)		(214	)		(89,747	)		(101,788	)		(191,535	)
Discoveries		-			-			-			-			-			-
Acquisitions		-			-			-			-			-			-
Dispositions		(467	)		(121	)		(589	)		(12,567	)		(41,583	)		(54,151	)
Economic		(48	)		(31	)		(78	)		(6,541	)		(2,088	)		(8,629	)
Production		(486	)		-			(486	)		(38,517	)		-			(38,517	)
December 31, 2009		3,779			2,808			6,587			496,544			340,388			836,932

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

	Ngls									Sulphur
	Gross Proved (Mbbl)			Gross Probable (Mbbl)			Gross Proved Plus Probable (Mbbl)			Gross Proved (Mlt)			Gross Probable (Mlt)			Gross Proved Plus Probable (Mlt)
December 31, 2008		10,660			7,230			17,889			2,145			944			3,089
Extensions		97			131			228			-			-			-
Improved recovery		-			-			-			-			-			-
Technical revisions		(538	)		(875	)		(1,413	)		(101	)		(82	)		(183	)
Discoveries		-			-			-			-			-			-
Acquisitions		-			-			-			-			-			-
Dispositions		(211	)		(294	)		(505	)		-			-			-
Economic		(83	)		(17	)		(100	)		(6	)		-			(6	)
Production		(659	)		-			(659	)		(72	)		-			(72	)
December 31, 2009		9,266			6,174			15,440			1,966			862			2,828

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

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	Total Reserves
	Gross Proved (Mboe)			Gross Probable (Mboe)			Gross Proved Plus Probable (Mboe)
December 31, 2008		124,324			91,164			215,488
Extensions		611			1,355			1,966
Improved recovery		-			-			-
Technical revisions		(15,530	)		(18,203	)		(33,733	)
Discoveries		-			-			-
Acquisitions		-			-			-
Dispositions		(2,773	)		(7,346	)		(10,119	)
Economic		(1,226	)		(396	)		(1,622	)
Production		(7,637	)		-			(7,637	)
December 31, 2009		97,768			66,575			164,343

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

Additional Information Relating to Reserves Data

Undeveloped Reserves

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

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

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 Undeveloped
Year	Crude Oil (Mbbl)		Natural Gas (MMcf)		Ngls (Mbbl)		Sulphur (Mlt)
2009		-		4,809		63		-
2008		-		26,773		550		141
2007		-		17,828		291		-
2006 & before		54		41,246		728		-

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

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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 Undeveloped
Year	Crude Oil (Mbbl)		Natural Gas (MMcf)		Ngls (Mbbl)		Sulphur (Mlt)
2009		-		29,845		202		80
2008		45		30,065		647		461
2007		381		35,578		507		-
2006 & before		1,033		172,279		3,350		-

(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 prices and costs change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information.

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

Future Development Costs

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

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Development Costs Deducted in Estimating Future Net Revenues(1)

	Proved		Proved Plus Probable
Year	Forecast Prices and Costs/Year ($000s)		Forecast Prices and Costs/Year ($000s)
Undiscounted
2010		34,549		73,200
2011		40,231		112,712
2012		45,088		145,199
2013		33,830		178,347
2014		10,499		73,022
Remaining		39,364		70,866
Total undiscounted		203,561		653,347
Total discounted @ 10% per year		149,589		484,541

(1)	Includes abandonment costs. Numbers may not add due to rounding.

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

OTHER OIL AND GAS INFORMATION

Oil and Gas Properties and Wells

The following table summarizes the location of the Corporation’s interests as at December 31, 2009 in crude oil and natural gas wells that are producing or that the Corporation considers to be capable of production.

Area	Producing Crude Oil Wells				Non-producing Crude Oil Wells(2)				Producing Natural Gas Wells				Non-producing Natural Gas Wells(2)				Total Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Alberta
Niton(3)		108		59.1		54		39.7		268		142.9		72		40.4		502		282.0
High River		2		1.2		5		4.0		111		92.1		54		49.5		172		146.7
Plains Belly River		-		-		-		-		732		669.0		107		94.1		839		763.1
Foothills(4)		-		-		-		-		26		25.2		11		9.7		37		34.9
Other		84		15.3		45		20.0		473		186.7		78		56.0		680		278.0
Total wells		194		75.5		104		63.7		1,610		1,115.8		322		249.8		2,230		1,504.7

(1)	Numbers may not add due to rounding.
(2)	A portion of the non-producing wells are wells considered capable of production but which, for a variety of reasons including but not limited to a lack of markets and lack of development, cannot be placed on production at the present time.
(3)	Includes Gilby and Bigoray properties.
(4)	Callum, Cowley and Todd Creek properties.

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Compton has high working interest and operatorship in its properties (84% and 85% respectively). 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 63,000 horsepower of compression totalling 120 MMcf/d of processing capacity with 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 for 75 MMcf/d of sour natural gas and 45 MMcf/d of sweet natural gas.

•	High River: In the High River area there is 9,125 horsepower (“hp”) installed with a gas compression capacity of 65 MMcf/d and 240 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 Plant are currently capable of compressing 19 MMcf/d and ultimately processing 50 MMcf/d through the two existing gas plants with the addition of field and/or plant compression. There is currently over 55 km of pipeline infrastructure in the operating area with minimal third party infrastructure in place.

•	Bigoray and Pembina: This is Compton’s primary oil production property. Facilities consist of satellites, water injection facilities, and associated oil batteries. There is 130 km of pipeline infrastructure in place in this operational area.

•

Edson, Niton, and McLeod: This foothills area property has compression capacity of 65 MMcf/d utilizing 13,000 hp, including the Compton McLeod River Gas Plant located at 7-34-54-14 W5M with 23 MMcf/d of capacity with 100% plant ownership. Additionally, there is over 260 km of pipeline infrastructure in the area.

•

Shallow Gas Properties: Compton’s shallow gas infrastructure consists of over 120 MMcf/d of compression capacity utilizing 32,500 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 Gas pipeline system at multiple sales locations.

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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 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 Wells
	Gas Wells				Oil Wells
Year	Gross (100%)		Company Gross		Gross (100%)		Company Gross
2003		1		1.0		-		-
2004		1		1.0		-		-
2005		12		8.0		-		-
2006		12		8.3		-		-
2007		10		7.5		1		1.0
2008		41		17.3		1		1.0
2009		14		8.5		-		-
Total		91		51.5		2		2.0

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, 2009.

Area	Gross Acres		Net Acres
Alberta
Niton(1)		162,624		132,988
High River		72,716		64,038
Plains Belly River		193,589		176,375
Foothills(2)		148,326		140,829
Other		95,522		80,928
Total(3)		672,777		595,158

(1)	Includes land for Gilby and Bigoray properties.
(2)	Callum, Cowley and Todd Creek properties.
(3)	Total land overstated due to multiple zones overlapping leases on various sections.

Compton expects that the rights to explore, develop and exploit approximately 120,818 net acres of undeveloped land may expire by December 31, 2010. Total land decreased from 2008 levels due to land expiries in areas viewed as less prospective by the Corporation, the majority of which were near the United States border. There are no material work commitments associated with the Corporation’s expiring undeveloped land holdings.

Forward Contracts

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. In 2008, Compton’s realized average field price was $57.26/boe, comprised of $8.17/Mcf for natural gas and $98.68/bbl for liquids.

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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 was revised in 2009 and 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.

Asset retirement obligations (“ARO”) cost calculations were derived from a combination of ERCB cost models, and typical industry experience and practices. The deemed ARO liability for Compton’s 2,200 net well sites and facilities is the sum of the calculated abandonment and reclamation liabilities adjusted for designated status as an active, inactive, abandoned, or problem site. Information regarding environmental remediation costs and other liability issues for site specific concerns were derived from a review of historical audit and assessment reports of sites and facilities. An inflation rate of 2% and a credit adjusted risk free rate of 10.5% was used in the fair value calculation.

Total asset retirement costs is estimated to be $231.5 million or $41.8 million when discounted at 10.5%, including the Mazeppa Processing Plant. The undiscounted ARO associated with pipelines and facilities is estimated to be $44.0 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 $18 million dollars in ARO costs between 2010 and 2014.

Tax Horizon

Compton has approximately $944.0 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 2009, Compton incurred approximately $68.3 million of capital costs in total (excluding acquisitions and divestitures): $7.0 million in exploration costs and $51.5 million in development costs. In addition, approximately $77.8 million was received on overriding royalty dispositions and an additional $9.2 million was received from property dispositions.

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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, 2009 and 2008.

	Year Ended December 31, 2009								Year Ended December 31, 2008
	Development				Exploratory				Development				Exploratory
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Natural gas		18		6		-		-		229		175		3		2
Crude oil		2		1		-		-		8		2		1		1
Dry and abandoned		-		-		-		-		9		6		1		1
Total		20		7		-		-		246		183		5		4
Success Ratio		100%								96%

In 2010, the Corporation expects to continue to focus its resources in Alberta, Canada. Compton’s overall objective for 2010 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 2010 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. Niton will be a continued focus area that will have its inventory expanded with the continued evaluation of the Rock Creek formation and other zones. High River’s focus will be on understanding the variability of the reservoir and the optimization of costs associated with drilling and completion. The Plains Belly River area will be focused on high-grading Belly River locations, evaluating deeper targets and optimizing operating costs in the area.

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.

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Gross Natural Gas and Liquids Production (1)

	Three Months Ended								Year Ended
Product Type	March 31, 2009		June 30, 2009		September 30, 2009		December 31, 2009		December 31, 2009
Natural gas (MMcf/d)		117		108		99		98		106
Natural gas (MMcf)		10,551		9,834		9,136		8,995		38,517

Natural gas liquids (boe/d)(2)		2,247		2,125		1,796		1,849		2,003
Natural gas liquids (Mboe)(2)		202		193		165		170		731

Crude oil (bbl/d)		1,408		1,303		1,412		1,206		1,332
Crude oil (Mbbls)		127		119		130		110		486

Total liquids (boe/d)		3,655		3,428		3,208		3,055		3,335
Total liquids (Mboe)		329		312		295		281		1,217

Total (boe/d)		23,194		21,440		19,760		19,351		20,922
Total (Mboe)		2,087		1,951		1,818		1,780		7,637

(1)	Numbers may not add due to rounding.

(2)	Includes sulphur.

2010 Production Estimates

Production volumes in 2010, as estimated in the Corporation’s reserve forecast from Netherland Sewell before deduction of royalties, are set forth below.

Reserves Category(1)	Crude Oil (bbl/d)		Natural Gas (MMcf/d)		Ngls (bbl/d)		Sulphur (lt/d)		Total (boe/d)
Proved
Developed producing		1,007		84		1,540		188		16,702
Developed non-producing		3		2		25		-		424
Undeveloped		-		4		77		-		682
Total proved		1,010		90		1,642		188		17,808
Probable		173		12		254		7		2,440
Total proved plus probable		1,184		102		1,896		195		20,248

(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 Ended
	March 31, 2009			June 30, 2009			September 30, 2009			December 31, 2009			December 31, 2009
Natural gas ($/Mcf)
Price	$	5.18		$	3.80		$	3.14		$	4.38		$	4.16
Royalties		(0.82	)		0.24			(0.25	)		(0.17	)		(0.26	)
Operating costs(1)		(1.70	)		(1.68	)		(1.60	)		(2.47	)		(1.85	)
Transportation costs		(0.11	)		(0.11	)		(0.11	)		(0.11	)		(0.11	)
Netback	$	2.55		$	2.25		$	1.18		$	1.63		$	1.94

Natural gas liquids ($/bbl)(3)
Price	$	34.90		$	41.21		$	44.50		$	48.97		$	42.01
Royalties		(13.41	)		(14.33	)		(14.00	)		(21.98	)		(15.78	)
Operating costs(1)		(10.20	)		(10.06	)		(9.59	)		(14.81	)		(11.10	)
Transportation costs		(0.87	)		(0.89	)		(1.57	)		(2.58	)		(1.43	)
Netback	$	10.42		$	15.93		$	19.34		$	9.60		$	13.70

Crude oil ($/bbl)
Price	$	43.85		$	64.18		$	69.32		$	69.56		$	61.48
Royalties		(5.50	)		(8.97	)		(18.39	)		(16.54	)		(12.31	)
Operating costs(1)		(13.44	)		(12.79	)		(11.39	)		(19.30	)		(14.07	)
Transportation costs		(0.87	)		(0.89	)		(1.57	)		(2.58	)		(1.45	)
Netback	$	24.04		$	41.53		$	37.97		$	31.14		$	33.65

Total liquids ($/bbl)
Price	$	38.35		$	49.94		$	55.42		$	57.10		$	49.79
Royalties		(10.36	)		(12.29	)		(15.93	)		(19.83	)		(14.39	)
Operating costs(1)		(11.45	)		(11.10	)		(10.38	)		(16.58	)		(12.29	)
Transportation costs		(0.87	)		(0.89	)		(1.57	)		(2.58	)		(1.44	)
Netback	$	15.67		$	25.66		$	27.54		$	18.11		$	21.67

Total ($/boe)
Price(2)	$	33.01		$	27.74		$	26.00		$	32.35		$	29.84
Royalties		(5.77	)		(0.78	)		(3.83	)		(4.01	)		(3.62	)
Operating costs(1)		(10.40	)		(10.23	)		(9.72	)		(15.09	)		(11.29	)
Transportation costs		(0.71	)		(0.71	)		(0.82	)		(0.98	)		(0.80	)
Netback	$	16.13		$	16.02		$	11.63		$	12.27			14.13

(1)

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

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

(3)	Includes sulphur.

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The following table indicates average daily gross production from important areas in respect of Compton’s assets for the year ended December 31, 2009:

Area	Crude Oil (Bbls/d)		Natural Gas (Mcf/d)		Ngls (Bbls/d)		Total (Boe/d)

Niton(1)		879		32,584		971		7,281
High River		7		24,700		538		4,662
Plains Belly River		356		37,148		330		6,878
Foothills(2)		-		4,103		67		751
Other		89		6,990		96		1,350
Total		1,332		105,525		2,002		20,922

(1)	Includes Gilby and Bigoray properties.

(2)	Callum, Cowley and Todd Creek properties.

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 263,573,461 Common Shares are issued and outstanding as fully paid and non-assessable shares as at February 25, 2010. No preferred shares are issued and outstanding as at February 25, 2010. 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 conditions attached to the shares of each series. Holders of preferred shares do not hold voting rights. The preferred shares are entitled to a priority over the Common Shares with respect to the payment of dividends and the distribution of assets upon the liquidation, dissolution, or winding-up of Compton.

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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. As Compton’s Stock Option Plan is a rolling plan that was approved at the Corporation’s annual and special meeting of shareholders on May 10, 2007, the shareholders are being asked to consider and, if thought fit, adopt a resolution approving all unallocated options issuable pursuant to the Stock Option Plan at the annual and special meeting of Compton shareholders to be held on May 13, 2010 (the “Meeting”). The unallocated options have been approved by a majority of the Board by director’s resolution approved at a meeting of the Board held on February 25, 2010.

If all unallocated options issuable pursuant to the Stock Option Plan are approved by a majority of shareholders at the Meeting, the Corporation will have the ability to continue granting options under the Stock Option Plan until 2013, which is three years from the date when shareholder approval is being sought. Previously allocated options will continue unaffected by the approval or disapproval of the Stock Option Plan resolution. If the Stock Option Plan resolution is not approved by shareholders, allocated options will not be available for reallocation if cancelled prior to exercise and unallocated options will not be available for grant.

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.

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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.

MARKET FOR SECURITIES

The outstanding Common Shares of the Corporation are listed on the TSX under the symbol CMT and on the New York Stock Exchange under the symbol CMZ. The following table sets out the high and low closing prices and average trading volume of Common Shares as reported by the TSX, for the periods indicated.

Period	TSX High Close		TSX Low Close		TSX Average Daily Trading Volume
2009
January	$	1.33	$	0.98		481,889
February	$	1.02	$	0.56		648,237
March	$	0.97	$	0.58		471,315
April	$	0.90	$	0.75		227,097
May	$	2.03	$	0.79		1,319,446
June	$	1.66	$	1.30		527,083
July	$	1.31	$	1.12		276,364
August	$	1.22	$	1.11		410,448
September	$	1.48	$	1.10		3,773,168
October	$	1.25	$	1.03		3,980,364
November	$	1.13	$	0.93		866,411
December	$	0.96	$	0.84		866,411

2010
January	$	1.11	$	0.95		1,391,878
February 1-25	$	0.98	$	0.88		545,036

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.

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INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

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

CEASE TRADE ORDERS, BANKRUPTCIES, PENALTIES OR SANCTIONS

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

In addition, none of those persons who are directors or executive officers of Compton or a shareholder holding a sufficient number of securities of Compton to affect materially the control of the 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 $220.0 million, arranged with a syndicate of banks, was comprised of a revolving term facility authorized at $190.0 million and a revolving working capital facility authorized at $30.0 million (see “General Development of the Business - Bank Debt and Senior Notes”);

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•

an Indenture dated as of November 22, 2005, among Compton Petroleum Finance Corporation, Compton, as parent guarantor, Hornet Energy Ltd., Compton Petroleum (partnership) and Compton Petroleum Holdings Corporation, as the initial subsidiary guarantors, and The Bank of Nova Scotia Trust Company of New York, as trustee, whereby, on November 22, 2005, Compton Petroleum Finance Corporation issued and sold U.S.$300 million aggregate principal amount of senior term notes, which are unsecured and bear interest semi-annually, in arrears on December 1 and June 1 of each year, at a rate of 7⅝% per year, with principal repayable on December 1, 2013. On April 4, 2006, Compton Petroleum Finance Corporation issued an additional U.S.$150 million aggregate principal amount of senior term notes under this Indenture on the same terms and conditions as the senior terms notes issued on November 22, 2005. The senior notes are guaranteed by Compton and the initial subsidiary guarantors; and

•

a purchase and sale and royalty agreement for the sale of an overriding royalty (“ORR”) to a third party. The first tranche of the transaction was for the sale of 2.5% of the royalty effective October 1, 2009; the second 1.25% closed on December 31, 2009 (effective October 1, 2009), and a further 0.50% closed in 2010. 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.

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, 2009 nor are there any such proceedings known to the Corporation to be contemplated.

During the year ended December 31, 2009, 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 Netherland Sewell, 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 rated Compton Petroleum Corporation’s U.S. $450 million 7⅝% Senior Notes as B and Caa1 respectively, as at December 31, 2009. 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.

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

Moody’s credit ratings on long-term structured finance obligations primarily address the expected credit loss an investor might incur on or before the legal final maturity of such obligations, incorporating the probability of default and the severity of the loss. Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from least credit risk to greatest credit risk of such securities rated. Moody’s applies numerical modifiers 1, 2 and 3 in each generic rating classification from Aa through Caa in its long-term debt rating system. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking, and the modifier 3 indicates that the issue ranks in the lower end of that generic rating category. According to the Moody’s rating system, debt securities rated B3 are considered speculative and are subject to high credit risk.

DIRECTORS AND OFFICERS

Directors

Mr. Peter Seldin, tendered his resignation as a director of the Corporation's Board effective October 6, 2009. Mr. Seldin joined Compton's Board of Directors in February 2008 in order to participate in a review of strategic alternatives. With the equity offering and the sale of overriding royalty interests in late 2009, Mr. Seldin stated that he believed Compton had taken important steps in the financial restructuring of the Corporation, and as such, stepped down from the Board.

The next Meeting is scheduled for May 12, 2009 at 3:30 p.m. (Calgary time) in the Historical Ballroom on the Fourth Floor of the Calgary Chamber of Commerce, 517 Centre Street South, Calgary, Alberta, Canada. 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. 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.

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Name and Municipality of Residence	Principal Occupation	Director Since
Mel F. Belich, Q.C. Calgary, AB, Canada	Chairman, Compton Petroleum Corporation. Mr. Belich has been Chairman and President of each of Enbridge International Inc. and Enbridge Technology Inc., and a director of numerous affiliates of Enbridge Inc., a pipeline company, including those in Europe and Latin America. Mr. Belich is the Chairman of the Board of Directors of Compton.	1993
J. Stephens Allan, F.C.A., ICD.D Calgary, AB, Canada	Consultant to RSM Richter LLP, one of the largest independent accounting, business advisory, and consulting firms in Canada. Mr. Allan has 39 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
David Fitzpatrick, P.Eng., C. Dir. Calgary, AB, Canada	Independent businessman and prior thereto was the President, CEO and Director of Shiningbank Energy Ltd. from 1996 to 2007 (acquired by PrimeWest Energy Trust (“PrimeWest”), an oil and gas royalty trust). Mr. Fitzpatrick has served as a Director of PrimeWest, Shiningbank Energy Income Fund, Platform Energy and Twin Butte Energy Ltd., each of which is or was an oil and gas company or trust.	2009
Tim Granger, P.Eng., Calgary, AB, Canada	President & Chief Executive Officer of the Corporation effective January 26, 2009. Mr. Granger previously served as Vice President, and Chief Operating Officer at Paramount Energy Trust, a natural gas royalty energy trust, and prior to that Mr. Granger was Managing Director of TAQA North, an oil and gas exploration company, following the acquisition of PrimeWest by TAQA in January of 2008. Prior to such acquisition Mr. Granger had served as the Chief Operating Officer of PrimeWest since 1999.	2009

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Name and Municipality of Residence

Principal Occupation

Director Since

R. 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., DirectCash Income Fund, the Alberta Children’s Hospital Foundation, and also serves on the Advisory Board of Marsh Canada.	2009
Irvine J. Koop, P. Eng. Calgary, AB, Canada	Independent businessman and prior thereto was the Chairman and Chief Executive Officer of IKO Resources Inc., a petroleum consulting firm. Mr. Koop was the President and CEO, Pipelines and Midstream of Westcoast Energy Inc., an energy products and services company (acquired by Duke Energy Company), and was the former president and CEO of Numac Energy, an oil and gas company (acquired by Anderson Exploration). Mr. Koop is also a Director of NAL Energy, a public oil and gas trust. Mr. Koop is the Chairman of the Corporate Governance, Human Resources and Compensation Committee.	1996
Warren M. Shimmerlik Bedford, New York, United States	Independent businessman. Previously, he was a Principal of COSCO Capital Management LLC, a private equity intermediary. Mr. Shimmerlik spent nearly two decades as a highly regarded Wall Street investment analyst, holding senior positions at Merrill Lynch & Company, L. F. Rothschild Unterberg Towbin and County NatWest Securities USA.	2009
Jeffrey T. Smith, P. Geol. Calgary, AB, Canada	Independent businessman and prior thereto, Chief Operating Officer of Northstar Energy Corporation, an oil and gas company (acquired by Devon Energy). He is also a Director of Provident Energy and Chairman of Intrepid Energy Corp., a private exploration and production company. Mr. Smith is Chairman of the Reserves, Operations and Environmental, Health and Safety Committee.	1999

Further information about the directors and the committees of the Board of Directors is set forth under the heading “Election of Directors” in the Corporation’s Management Proxy Circular dated February 25, 2010 relating to the Meeting to be held on May 12, 2010, 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 Occupation

Tim 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.

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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 25 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.

Marc R. Junghans, P. Geol. Calgary, Alberta	Vice President, Exploration of the Corporation. In his career, Mr. Junghans has successfully explored for unconventional hydrocarbons in every province of Western Canada and portions of the Northern U.S., including extending the Deep Basin region of western Canada with his discovery of the Compton’s High River BQ pool. Prior to joining Compton, he held various petroleum geological positions of increasing importance at a number of Canadian oil and gas companies.

Shannon L. Ouellette, M. Eng., P. Eng. Calgary, Alberta	Vice President, Operations & Development of the Corporation. Ms. Ouellette brings extensive experience in operations and asset development through her 17 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 25, 2010 the directors and officers of Compton as a group beneficially owned or controlled, directly or indirectly, 4.7 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.

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), Tim Granger (ex officio, non-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.

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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 paid or accrued by the Corporation with respect to fees payable to Grant Thornton LLP for audit and audit-related engagements (including separate audits of subsidiary entities, financings, and regulatory reporting requirements), tax and other services in the fiscal years ended December 31, 2009 and 2008 were as follows:

Type of Service	Fiscal 2009		Fiscal 2008
Financial statement and internal controls audit	$	1,030,849	$	860,974
Audit related		51,636		55,765
Tax		21,945		-
Other non-audit	$	137,000		1,220
Total	$	1,241,430	$	917,959

Financial statement audit fees in fiscal 2009 and 2008 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 2009 and 2008 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 and the United States Public Company Accountability and Oversight Board.

Tax services performed by Grant Thornton outside of normal audit procedures during 2009 related to debt restructuring and potential tax planning opportunities. Other non-audit fees relate to services provided during the issue of the 2009 prospectus as well as the preparation of a scoping, planning and 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.

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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 25, 2010, relating to the Annual and Special Meeting of Shareholders to be held on May 12, 2010. 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, 2009, included in the Corporation’s 2009 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:

	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.

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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. In several sections that follow, Compton has used the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip and does not represent a value equivalency at the wellhead. However, this does not represent a value equivalency at the plant gate where Compton sells its production volumes and therefore may be a misleading measure if used in isolation.

Forward-Looking Statements

Certain information regarding the 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”). 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;

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•

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 therewith 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 the Compton’s annual Management's Discussion and Analysis under the headings “Liquidity and Capital Resources”, “Capital Structure”, “Outlook and Guidance for 2010” 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 and elsewhere in this AIF and they include, but are 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;

•

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;

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(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 2010 involve greater risks and require longer term assumptions and estimates from those for 2010, 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

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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, 2009, 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 Vice President, Operations & Development

/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 25, 2010

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