EX-20 2 ex20-1form40f_2004.txt EXHIBIT 20.1 EXHIBIT 20.1 ------------ [GRAPHIC OMITTED] [LOGO-COMPTON PETROLEUM CORPORATION] ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2004 COMPTON PETROLEUM CORPORATION March 23, 2005 TABLE OF CONTENTS PAGE ABBREVIATIONS AND CONVERSION FACTORS........................................2 NOTES AND DEFINITIONS.......................................................3 FORWARD LOOKING STATEMENTS..................................................7 CORPORATE STRUCTURE.........................................................8 GENERAL DEVELOPMENT OF THE BUSINESS.........................................8 DESCRIPTION OF THE BUSINESS.................................................9 STATEMENT OF RESERVES DATA.................................................15 PRICING ASSUMPTIONS........................................................19 ADDITIONAL INFORMATION RELATING TO RESERVES DATA...........................21 DIVIDENDS..................................................................27 CAPITAL STRUCTURE..........................................................27 CONFLICTS OF INTEREST......................................................28 INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS................28 INTERESTS OF EXPERTS.......................................................29 RATINGS ...................................................................29 DIRECTORS AND OFFICERS.....................................................29 AUDIT, FINANCE AND RISK COMMITTEE INFORMATION..............................31 COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE...........................31 EXTERNAL AUDITOR FEES......................................................31 TRANSFER AGENT AND REGISTRAR...............................................32 RISK FACTORS...............................................................32 ADDITIONAL INFORMATION.....................................................33 SCHEDULE A.................................................................34 SCHEDULE B.................................................................36 SCHEDULE C.................................................................38 -1- ABBREVIATIONS AND CONVERSION FACTORS ABBREVIATIONS The following are abbreviations of technical term used throughout this Annual Information Form: "BBL" means barrel; "BBLS" means barrels; "BCF" means billion cubic feet; "BOE" means barrels of crude oil equivalent; "BOEPD" or "BOE/D" means barrels of crude oil equivalent per day; "BOPD" means barrels of crude oil per day; "MBBLS" means thousand barrels; "MBOE" means thousand barrels of crude oil equivalent; "MCF" means thousand cubic feet; "MMBBLS" means million barrels; "MMBOE" means million barrels of crude oil equivalent; "MMCF" means million cubic feet; "MCFE" means thousand cubic feet equivalent; "MMCFD" or "MMCF/D" means million cubic feet per day; "MSTB" means thousand stock tank barrels; and "NGLS" means natural gas liquids. -2- CONVERSION FACTORS To conform with common usage, Standard Imperial Units of measurement are used in this Annual Information Form to describe exploration and production activities. The following table sets forth conversions between Standard Imperial Units and the International System of Units (or metric units). ------------------------------------------------------------------------------- TO CONVERT FROM TO MULTIPLY BY ------------------------------------------------------------------------------- mcf cubic metres 0.028174 boe mcfe 6.000 cubic metres of gas cubic feet 35.490 bbls cubic metres 0.159 cubic metres of oil bbls 6.289 feet metres 0.305 metres feet 3.281 miles kilometres 1.609 kilometres miles 0.621 acres hectares 0.405 hectares acres 2.471 ------------------------------------------------------------------------------- NOTES AND DEFINITIONS The determination of oil and natural gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved, probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability, statistics and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions. "RESERVES" are estimated remaining quantities of oil, natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on (a) analysis of drilling, geological, geophysical and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates. "PROVED" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Nine out of ten times, proved reserves are likely to increase. "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. "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. "UNDEVELOPED" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure, when compared to the cost of drilling a well, is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. -3- In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status. "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. The following terms, when used in this document, have the following meanings, as set forth in National Instrument 51-101: "ASSOCIATED GAS" means the gas cap overlying a crude oil accumulation in a reservoir. "CONSTANT PRICES AND COSTS" means prices and costs used in an estimate that are: (a) the company's prices and costs as at the effective date of the estimation, held constant throughout the estimated lives of the properties to which the estimate applies; and (b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the company is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a). For the purpose of paragraph (a), the reporting issuer's prices will be the posted price for oil and the spot price for gas, after historical adjustments for transportation, gravity and other factors. "COMPANY" or "COMPTON" or "WE" means Compton Petroleum Corporation. "CRUDE OIL" or "OIL" means a mixture that consists mainly of pentanes and heavier hydrocarbons, which may contain sulphur and other non-hydrocarbon compounds, that is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated. It does not include solution gas or natural gas liquids. "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. -4- "DEVELOPMENT WELL" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive. "EUB" means the Alberta Energy and Utilities Board. "EXPLORATION COSTS" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs"); (b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defense and the maintenance of land and lease records; (c) dry hole contributions and bottom hole contributions; (d) costs of drilling and equipping exploratory wells; and (e) costs of drilling exploratory type stratigraphic test wells. "EXPLORATORY WELL" means a well that is not a development well, a service well or a stratigraphic test well. "FIELD" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to denote localized geological features, in contrast to broader terms such as "basin", "trend", "province", "play" or "area of interest". "FUTURE PRICES AND COSTS" means future prices and costs that are: (a) generally accepted as being a reasonable outlook of the future; (b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Company is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a). "FUTURE INCOME TAX EXPENSES" means future income tax expenses estimated year-by-year: (a) making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities; (b) without deducting estimated future costs (such as Crown royalties) that are not deductible in computing taxable income; (c) taking into account estimated tax credits and allowances; and -5- (d) applying to the future, pre-tax cash flows relating to the Company's oil and gas activities and the appropriate year end statutory tax rates, taking into account future tax rates already legislated. "FUTURE NET REVENUE" means the estimated net amount to be received with respect to the development and production of reserves estimated using constant prices and costs or forecast prices and costs. "GROSS" means: (a) in relation to the Company's interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company; (b) in relation to wells, the total number of wells in which the Company has an interest; and (c) in relation to properties, the total area of properties in which the Company has an interest. "NATURAL GAS" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain natural gas liquids. Natural gas can exist in a reservoir either dissolved in crude oil (solution gas) or in a gaseous phase (associated gas or non-associated gas). Non-hydrocarbon substances may include hydrogen sulphide, carbon dioxide and nitrogen. "NATURAL GAS LIQUIDS" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons. "NET" means: (a) in relation to the Company's interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves; (b) in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and (c) in relation to the Company's interest in a property, the total area of properties in which the Company has an interest multiplied by the working interest owned by the Company. "NON-ASSOCIATED GAS" means an accumulation of natural gas in a reservoir where there is no crude oil. "OPERATING COSTS" or "PRODUCTION COSTS" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment, facilities and other costs of operating and maintaining those wells and related equipment and facilities. "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 -6- (c) an agreement with a foreign government or authority under which a reporting issuer participates in the operation of properties or otherwise serves as producer of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer). A property does not include supply agreement 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 PROPERTY" means a property or part of a property to which reserves have been specifically attributed. "RESERVOIR" means a porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. "SERVICE WELL" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion. "SHUT IN WELL" means a well which is capable of economic production or which the Company considers capable of production but which for a variety of reasons, including, but not limited to, lack of markets or development, is not placed on production at the present time. "SOLUTION GAS" means natural gas dissolved in crude oil. "STRATIGRAPHIC TEST WELL" means a geologically directed drilling effort, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (a) "exploratory type" if not drilled into a proved property; or (b) "development type", if drilled into a proved property. Development type stratigraphic wells are also referred to as "evaluation wells". "SUPPORT EQUIPMENT AND FACILITIES" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps and division, district or field offices. "UNPROVED PROPERTY" means a property or part of a property to which no reserves have been specifically attributed. "WELL ABANDONMENT COSTS" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. Costs of abandoning the gathering system or reclaiming the wellsite are not included. FORWARD LOOKING STATEMENTS This Annual Information Form may contain certain forward looking statements under the meaning of applicable securities laws. Forward looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact. Although Compton believes that the expectations reflected in such forward looking statements are reasonable, it can give no assurance that such expectations will -7- prove to have been correct. There are many factors that could cause forward looking statements not to be correct, including risks and uncertainties inherent in the Company's business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards and mechanical failures, uncertainties in the estimates of reserves and in projections of future rates of production and timing of development expenditures, general economic conditions, and the actions or inactions of third-party operators. The Company's forward looking statements are expressly qualified in their entirety by this cautionary statement. CORPORATE STRUCTURE NAME AND INCORPORATION Compton was incorporated by articles of incorporation pursuant to the provisions of the Business Corporations Act (Alberta) on October 15, 1992, as 544201 Alberta Ltd. The articles were amended on April 13, 1993, to change the Company's name to Compton Petroleum Corporation and the Company commenced active business operations in July 1993. The articles were amended on November 21, 1994 and March 1, 1996, in order to remove the private company restrictions contained in the articles. A further amendment was made to the articles on September 1, 1998, in order to create a class of preferred shares issuable in series. The Company's head and principal office is located at Suite 3300, 425 - 1st Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada, T2P 3L8. Compton's registered office is located at Suite 3000, 237 - 4th Avenue, S.W., Fifth Avenue Place, West Tower, Calgary, Alberta, Canada, T2P 4X7. Effective January 31, 2001, a general partnership called Compton Petroleum was formed under the laws of Alberta between Compton and Compton's wholly owned subsidiary 867791 Alberta Ltd. On July 16, 2001, the partnership agreement was amended to include Hornet Energy Ltd. Each partner has contributed a majority of its producing assets to the partnership. The majority of Compton's production activities are carried out through the partnership. Effective May 2, 2003, MPP Ltd. ("MPP LTD."), a wholly-owned subsidiary of the Company, was formed under the laws of Alberta. On June 16, 2003, MPP Ltd., as general partner, and 1051940 Alberta Ltd., as limited partner, formed a limited partnership called the Mazeppa Processing Partnership. The Mazeppa Processing Partnership owns, among other assets, the Mazeppa and Gladys gas plants. GENERAL DEVELOPMENT OF THE BUSINESS Compton is an Alberta based independent public company actively engaged in the exploration, development and production of natural gas, ngls and crude oil in the Western Canadian Sedimentary Basin (the "WCSB") in Canada. The Company's capital stock is listed and trades on the Toronto Stock Exchange (the "TSX") under the trading symbol "CMT", and is included in both the S&P/TSX Composite Index and the TSX Mid-Cap Index. Compton commenced operations in 1993 with $1 million of share capital, a small dedicated technical team and a large seismic database. The objective was to build a company through internal, full cycle exploration, complemented by strategic acquisitions. Compton's goal was to create a company capable of long term sustained growth with a primary focus on natural gas. Compton's focus and strategy have remained unchanged since conception. THREE YEAR HISTORY In 2002, Compton continued to focused on the exploration and development of its internally generated prospects. The Company's $155 million capital program included the drilling of 87 gross (64 net) wells with a success rate of 90%. Compton's total established reserves increased 19.8 mmboe from 83.7 mmboe to 103.5 mmboe during 2002. During 2002, the Company acquired a 50% working interest and operatorship of a 30 mmcf/d natural gas plant, 95 sections of contiguous undeveloped lands and 1,911 mboe of established, deep tight natural gas reserves at Callum. In December 2002, Compton expanded its land position at Niton through a swap for 100 sections of high working -8- interest lands for non-operated minor working interests in the southern Peace River Arch area. Both Niton and Callum are now core areas for Compton. In 2003, Compton focused on the resolution of pipeline and facility constraints in its Southern Alberta core area. The Mazeppa Processing Partnership purchased the Mazeppa and Gladys natural gas plants with related compression facilities and pipelines in Southern Alberta. The partnership is managed and controlled by Compton and provided Compton flexibility to pursue and accelerate various processing alternatives, including plant expansions. The Hooker pipeline system was expanded to 80 mmcf/d and natural gas production from Brant was offloaded to the ATCO sales pipeline. With processing restrictions removed, Compton intends to continue to aggressively explore lands adjacent to the Mazeppa, Gladys and Brant pipeline and plant infrastructures. The Company continued to pursue the exploration and development of its assets and prospects in 2003. The Company's capital program totaled approximately $285 million, including the consolidation of the Mazeppa gas plant. The Company drilled 168 gross (134 net) wells in 2003 with an 83% success rate. Expansion of the Mazeppa gas plant from 90 mmcf/d to 135 mmcf/d through the addition of 45 mmcf/d of additional sweet gas processing capacity, was completed and operational on June 1, 2004. Compton's processing capacity in Southern Alberta is now 200 mmcf/d and free of restrictions. The Mazeppa Processing Partnership completed the $75 million external financing of the acquisition, expansion and operations of the Mazeppa facilities and repaid funds borrowed from Compton. Compton continues to be very optimistic about its five separate resource plays including Coalbed Methane in the Horseshoe Canyon (Edmonton Formation), plains Belly River, thrusted foothills Belly River, Hooker Basal Quartz sands in Southern Alberta and the Gething/Rock Creek sands at Niton in Central Alberta. In 2004, Compton drilled 186 gross (146 net) wells with a 90% success rate. Of the wells drilled, 77% were classified as development wells and 33% were classified as exploratory wells. The increasing percentage of development wells is reflective of the increasing maturity of the Company's oil and natural gas plays. Capital expenditures totaled $323 million in 2004. In 2004, Compton added approximately 26 mboe to its proved plus probable reserves through drilling successes, acquisitions and extensions. Total proved plus probable reserves increased 22% from the prior year to 145 mboe. DESCRIPTION OF THE BUSINESS EXPLORATION AND PRODUCTION OPERATIONS Compton's exploration, development and exploitation activities are concentrated principally in three core areas: 1) Southern Alberta targeting the plains Belly River, Horseshoe Canyon coalbed methane, Hooker Basal Quartz and thrusted, foothills Belly River at Callum; 2) Central Alberta targeting the Gething/Rock Creek at Niton; and 3) the Peace River Arch area producing from the Charlie Lake pool at Cecil/Worsley. These areas are the geographic focus of Compton's seismic database and are areas in which Compton's Management ("MANAGEMENT") and staff have significant technical expertise and operational experience. MAZEPPA PROCESSING PARTNERSHIP In June of 2003, Mazeppa Processing Partnership ("MPP") acquired certain midstream assets from an independent third party. The assets consist of major natural gas gathering and processing facilities in southern Alberta. Compton does not have an ownership position in MPP. Through a management agreement, Compton manages the activities of MPP and is therefore considered to be the primary beneficiary of MPP's operations. As a result, Compton consolidates the accounts of MPP for reporting purposes in accordance with the guidelines issued by the Accounting Standards Board, in Accounting Guideline AcG-15, "Consolidation of Variable Interest Entities." The results of the midstream activities are immaterial to Compton's consolidated financial condition. EMPLOYEES As at December 31, 2004, Compton had 115 full-time employees in its Calgary office and 33 full-time employees at field locations. -9- BUSINESS PLAN AND OPERATING STRATEGY The Company's business plan is to grow Compton's reserves and maximize production and cash flow from its core geographic areas and other areas where Compton has technical expertise. Management believes the Company is implementing this objective by focusing on the efficient exploration, development and exploitation of its properties, controlling operating costs, adding economic reserves and production and making strategic acquisitions in its core areas. Compton has experienced, professional, management, technical and support staff sufficient to carry out its business plan and its current exploration, exploitation, development, production, engineering, financial and administrative functions. The Company's operating strategy includes the components set forth below: CONCENTRATE ON CORE GEOGRAPHIC AREAS. The Company has established and is expanding its core areas within the WCSB. This geographic core area focus provides Compton with a balanced portfolio of exploitation, exploration and development prospects. Compton has developed and continues to develop its natural gas and crude oil reserves primarily through the internal generation of opportunities. This focus provides the Company with the opportunity for high working interests, enabling Compton to control the timing of capital expenditures and facilitates the efficient management of its activities. Compton's intention is to generate exploration opportunities and to significantly increase its undeveloped land base within the WCSB. FOCUS ON NATURAL GAS. Compton has gained considerable technical expertise and achieved significant success in exploring for deeper, larger, low decline natural gas reservoirs. The Company plans to continue to focus on finding and developing long life natural gas reserves. PURSUE FULL CYCLE EXPLORATION COMPLEMENTED BY SELECTIVE ACQUISITIONS. The Company plans to continue to reinvest internally generated cash flow to fund the growth of its exploration and development programs and to further increase Compton's undeveloped land base to maintain a growing inventory of drilling prospects in its core geographic areas. The Company has also successfully completed and integrated a series of strategic acquisitions to grow Compton's reserves and production base and enhance the level of technical expertise in its core areas. Depending on commodity price cycles, the Company may defer exploration projects and enhance its operations and prospects through strategic acquisitions. CONTROL OF INFRASTRUCTURE AND OPERATORSHIP. The Company believes that control over gathering and processing infrastructure and operatorship of drilling programs will continue to be critical to the success of Compton's full-cycle exploration program. Compton currently owns or has access to critical infrastructure in each of its three primary producing areas. Compton operates approximately 75% of its existing production and, as of December 31, 2004, had a 72% average working interest in its undeveloped lands. This position allows the Company to exercise discretion in determining the timing and methodology of Compton's ongoing exploitation, exploration and development programs. The Company expects to continue to expand its position in its core operating areas to maximize operating efficiencies and maintain control over ongoing capital programs. MAINTAIN A LARGE PORTFOLIO OF UNDEVELOPED LAND AND SEISMIC DATABASE. As of December 31, 2004, the Company has assembled a significant portfolio of undeveloped land and has working interests in 1,019,854 (729,429 net) acres of undeveloped land. Management believes that Compton's existing portfolio of undeveloped land is sufficient to produce at least five years of internally generated exploration and development prospects. Additionally, the Company holds a quality, complementary seismic database. The Company's rights to approximately 100,700 kilometres of two-dimensional ("2D") seismic and 2,200 square kilometres of three-dimensional ("3D") seismic are concentrated primarily in areas throughout Compton's core operating areas within Alberta. Compton will continue to utilize the seismic database to evaluate and generate future prospects and to assist in maintaining growth of the Company. MAINTAIN FINANCIAL FLEXIBILITY. The Company is committed to maintaining financial flexibility to allow Compton to pursue its full cycle exploration program in periods of low commodity prices. The Company intends to maintain flexibility to respond to opportunities for strategic acquisitions as they arise. Compton has historically funded its -10- exploration and development capital program through internally generated cash flow and has financed acquisitions through debt, the issuance of common shares or a combination thereof. PRINCIPAL PROPERTIES SOUTHERN ALBERTA Southern Alberta continues to be the focus of Compton's activities. The Company has approximately 1,220 (998 net) sections of land. The area is prospective for multiple zones, including the plains Belly River, foothills type, multiple thrusted Belly River at Callum, Basal Quartz at Hooker and the Wabamun/Crossfield. Additional upside exists in the shallower Edmonton Formation/Horseshoe Canyon Coals. In 2004, Compton drilled 101 gross (88 net) wells in Southern Alberta with a 94% success rate. The Company plans to spend $251 million in Southern Alberta in 2005 and drill 269 wells. HORSESHOE CANYON COAL BED METHANE Compton holds approximately 960 net sections of land in Southern Alberta within the dry Horseshoe Canyon Coal Bed Methane ("CBM") fairway. Following an internal geological assessment of the CBM potential in Compton's lands, the Company is proceeding to quantify the CBM resource base. During the third quarter of 2004, the Company re-completed six existing Belly River wells targeting the uphole Horseshoe Canyon Coals, primarily at Centron, Gladys and Brant. Results were similar to competitor's CBM wells immediately north of Compton's acreage. Preliminary internal resource evaluations of the Edmonton/Horseshoe Canyon Coals estimate gas-in-place is eight to nine bcf per section. Six to eight wells will be required to fully develop the reserves, assuming a recovery rate of 50-60%. Compton is in a unique position regarding future Edmonton/Horseshoe Canyon development. The Company has previously drilled 250 Belly River wells across the Southern Alberta core area, primarily on single section spacing. These existing wells were drilled through the Edmonton formation targeting the Belly River zone. Behind pipe are unperforated coals and Edmonton sands of similar quality and quantity to successful competitor CBM plays on lands that lie immediately to the north and south of Compton's landholdings. With the 2005 budget planning an additional 186 Belly River wells, Compton will have over 400 wellbores available for uphole CBM recompletions by year end 2005. The cost to drill, complete, equip and tie-in a well targeting solely Edmonton/CBM is $400,000, whereas the cost to workover an existing Belly River well for CBM is only $150,000-$200,000. Compton currently has an extensive network of low pressure pipelines and strategically placed compressors throughout Southern Alberta to produce the Company's Belly River gas wells. As a result little infrastructure will be required to initiate Edmonton/CBM production. Compton has insignificant CBM reserves booked as at December 31, 2004, despite having five wells on continuous production since year end. Quantifying the reserve and delivery potential of the Edmonton/CBM over Compton's large land spread is a key objective in 2005. Compton has six CBM pilot projects underway, with results expected by the middle of the fourth quarter of 2005. The pilots will not delay Compton's plan to continue uphole recompletions of existing Belly River wells. PLAINS BELLY RIVER AT CENTRON, GLADYS AND BRANT The plains Belly River consists of five to six multi-stacked sands, which occur extensively over 960 net sections of Compton's Southern Alberta core area. The Company has an average working interest of 90% in this play. Wells produce approximately 150-200 mcf/d and cost $500,000 to drill, complete, equip and tie-in. Based on internal work, the Company estimates gas-in-place could be in the range of six to eleven bcf and recoveries may average 0.6+ bcf per well. Ultimate recoveries will depend on well density. Compton believes that four to six wells per section will optimize recovery of the Belly River gas. -11- In 2004, Compton drilled 60 gross (54 net) wells across the Centron, Gladys and Brant areas with all wells encountering multiple pay sections. To date, the Company has drilled 250 wells targeting the Belly River sands. The pipeline and compression system that Compton owns and operates in Southern Alberta is extensive. Historically the majority of Compton's drilling has been on one section spacing. During the second half of 2004, Compton received approval to proceed with two wells per section on seven townships of land. This effectively doubles the Company's current plains Belly River drilling inventory. The Company plans to drill 183 Belly River wells in 2005. CALLUM THRUSTED BELLY RIVER Applying expertise developed in the Company's plains Belly River exploration, Compton is targeting thrusted, stacked multiple Belly River tight sandstones at Callum. The Company has a 60% working interest in 110 sections of land on trend. Based upon limited initial drilling results, the potential gas in place is estimated to be 80 bcf per section, with ultimate recoveries depending upon well density. Compton has an average working interest of 60% in the play. Drilling in the Callum area is completed from pads with an eight well capability. Each new well costs approximately $2.5 million to drill, complete, equip and tie-in, with six to eight wells required per section to develop this play. Seven wells to date have been drilled in the feature, with recent completions averaging approximately 1 mmcf/d per well. In 2004, three directional wells were drilled from a pad constructed immediately south of the Callum gas plant, plus two additional wells north of the plant. Results were encouraging, however, it is apparent that completion design is the key to unlocking this technically challenging play. Callum has the potential to become a very significant resource play for Compton and time spent assessing completion techniques is critical to the future development of this play. Quarter section spacing over nine sections was approved by the EUB in the third quarter of 2004. Site assessment for the next drilling pad was completed in the fourth quarter of 2004, with drilling expected to commence early in 2005. Compton plans to drill 21 wells at Callum in 2005. HOOKER BASAL QUARTZ The Hooker trend targets tight Lower Cretaceous Basal Quartz sandstones. This play covers an extensive area of approximately 244 net sections, with Compton's working interest averaging 75%. Current production extends over four townships, with the outer boundaries of the play continuing to be expanded. The majority of the 110 gross (89 net) gas wells drilled to date at Hooker were on single section spacing, however, two wells per section spacing across 26 sections was approved by the EUB in the third quarter of 2004. Further downspacing is being applied for. Compton feels the pool can ultimately be drilled on three wells per section spacing. Wells cost an average of $1.5 million to drill, complete, equip and tie in, while production averages 1 mmcf/d. Mapping by the Company suggests this play has the potential to grow to nine townships with reserves in place of up to 15-20 bcf per section. The same work suggests the Hooker trend has the potential to contain up to 1.5 tcf of gas-in-place potential, net to the Company. With recoveries of 65%, Hooker's resource potential is in excess of 500 bcf of net gas reserves. In 2004, 25 gross (22 net) gas wells were drilled, extending the pool boundary five miles to the north and 1.5 miles to the southeast. The Company received downspacing approval on the southeast Hooker extension and is currently proceeding with an additional application for downspacing at the northern end of Hooker. In 2005, the Company plans to drill 35 wells at Hooker. SOUTHERN ALBERTA FACILITIES On June 1, 2004, a 45 mmcf/d sweet gas expansion at the Mazeppa plant was completed resulting in 90 mmcf/d sour and 45 mmcf/d sweet processing capacity. Compton gained control and management of the Mazeppa and Gladys gas -12- plants and related infrastructure through the acquisition of the facilities by Mazeppa Processing Partnership in July of 2003. With the completion of the Mazeppa sweet gas expansion, Compton's working interest processing capacity in Southern Alberta is now 200 mmcf/d. Available processing capacity will be sufficient to accommodate the Company's production additions for the next few years. Future expansions, when required, can be undertaken by Compton as operator, ensuring timely completion. CENTRAL ALBERTA Central Alberta provides Compton with excellent exploration and development drilling opportunities using similar techniques gained through years of experience from Southern Alberta Deep Basin type, tight gas drilling. Compton holds 757 (407 net) sections of land, the majority located approximately 100 km West of Edmonton. In 2004 Compton drilled 46 gross (32 net) wells with an 83% success rate. The Company plans to spend $68 million in Central Alberta in 2005 and drill 58 wells. NITON GETHING The Niton area is characterized by multi-zone, deep basin type targets analogous to the Southern Alberta Hooker area. Compton's primary gas targets include Rock Creek (Jurassic) and Gething. Secondary targets include Bluesky, Viking and Cardium. The Company has assembled 126 net sections, with an average working interest of 75%. In 2004, the Company drilled and cased 16 gross (15 net) gas wells. To date, 30 gross gas wells have been drilled with average production of 1 mmcf/d including liquids at an average cost of $1.5 million to drill, complete, equip and tiein. The Company anticipates the gas-in-place could be in the range of 10-12 bcf per section, with a projected recovery of 75%. In 2004, Compton received downspacing approval on 18 sections for two wells per section, with further downspacing approval pending. The Company expects two to three wells will be required to fully develop this area, with 26 wells planned in 2005. During the second quarter of 2004, Compton acquired all of the issued and outstanding shares of Redwood Energy, Ltd., a junior oil and gas company active in the Niton Area. Through the acquisition, the Company gained undeveloped lands, workover opportunities on existing wells, reserves, production and control of a 35 km gathering system, key to area development. The Compton owned McLeod River gas plant was operating at maximum capacity in the third quarter of 2004 as a result of the Company's successful drilling program at Niton. The gas plant was expanded from 10 mmcf/d to 20 mmcf/d in the fourth quarter of 2004. A 10 mmcf/d booster compressor at Niton was installed and operational early in the third quarter of 2004. PEACE RIVER ARCH The Peace River Arch area, located north of Grande Prairie, contains multi-zone potential for exploration and development opportunities. This area includes both light oil production at Cecil/Worsley and natural gas exploration at Howard and Pouce Coupe. The Company holds 306 (182 net) sections acres of land in the area. In 2004, Compton drilled 39 gross (26 net) wells in the Arch with a 92% success rate. The Company plans to spend $51 million in the area in 2005 and drill 56 wells. CECIL/WORSLEY Together, the Cecil and Worsley Charlie Lake pools are estimated to hold in excess of 200 million barrels of oil-in-place. Compton drilled 10 wells at Worsley in 2004, doubling the estimate of original oil-in-place. As a result of the Company's success with the two existing waterflood pilots, Compton made an application for a pool wide waterflood on the Charlie Lake H and J pool. Approval was granted in February 2005. Waterflooding in the Worsley Charlie Lake H and J pool is projected to increase the ultimate recovery rate from 5-7% to 15-17%. Pipelines in the Worsley area were expanded to prepare -13- for implementation of the full scale waterflood over the next two years. A battery expansion was also completed to accommodate future drilling plans. In 2005, Compton anticipates drilling 39 Charlie Lake extension and infill wells at Worsley. Compton participated in drilling 12 horizontal Charlie Lake oil wells at Cecil in 2004. The Company has a 40% working interest in the play, which is operated by a major industry partner. The success of the Cecil program has prompted Compton to expand the 2005 drilling program to 20 wells. COMPETITIVE CONDITIONS While the demand for natural gas continues to grow, production may be peaking. Natural gas wells in the WCSB continued the trend of lower initial production rates and higher first year decline rates, resulting in an overall increase of decline rates in the WCSB. In order to maintain current production levels, producers must increase drilling and pursue unconventional sources of natural gas. Unconventional sources of natural gas are necessary to offset conventional natural gas declines and provide the production growth necessary to fulfill increasing demand. Unconventional sources include coalbed methane, shale gas, liquefied natural gas and tight gas. Tight gas, which comprises 80% of Compton's reserves, is expected to be the largest unconventional form of natural gas production in the future. The Canadian oil and natural gas industry is also aggressively pursuing coal bed methane potential and the early results show significant upside. These new resource plays require a large upfront land base, technical expertise, experience and difficult project economics which puts more pressure on the industry. Drilling rigs, service rigs, equipment and experienced crews continue to operate at or near maximum capacity, which has resulted in escalating drilling costs and inefficiencies. Strong demand for experienced professionals has caused a significant increase in salaries and workloads, further adding to inefficiency in the industry. Land prices also continue to increase and are consuming an increasing portion of annual budgets and adding considerably to finding, development and acquisition ("FD&A") costs. Deeper drilling and more complex plays have contributed to higher FD&A costs for the industry in general. Additionally, the increasing complexity and ever changing government rules regarding license applications, environmental and governance matters is adding significantly to overall costs, workloads and timing of operations. The end result is that while commodity prices are strong, the cost, effort and time of doing business have also risen dramatically. ENVIRONMENTAL PROTECTION Compton believes in the importance of protecting the environment and is committed to conducting all operations in a safe manner that minimizes environmental impact. The Company is required to remove production equipment, batteries, pipelines, gas plants and restore land at the end of oil and natural gas operations. The Company estimates these costs in accordance with existing laws, contracts and other policies and records an expense in the consolidated financial statements over the useful life of the assets. SEISMIC The Company owns rights to copies of, and rights to utilize, large seismic databases for its internal purposes. The proprietary rights of such databases are owned mostly by third parties (although the proprietary rights of some databases are owned by the Company). These databases include conventional 2-D seismic covering 101,449 kilometres and 3-D seismic data shot over 3,063 square kilometres. This data is concentrated primarily in areas throughout Compton's core operating areas within Alberta. Additionally, the Company has rights to use 6,200 kilometres of seismic covering areas in southern Manitoba. These large seismic databases are utilized by the Company's exploration team in exploration and acquisition decisions of the Company. -14- STATEMENT OF RESERVES DATA Compton's interests in its natural gas and crude oil properties as of December 31, 2004, have been evaluated in a report (the "REPORT") as of December 31, 2004, prepared by the independent international integrated petroleum engineering and geological firm, Netherland, Sewell & Associates, Inc. ("NETHERLAND SEWELL"). The following summary of the Company's reserves is calculated and reported in accordance with National Instrument 51-101, "Standards of Disclosure for Oil and Gas Activities". Assumptions and qualifications relating to costs, prices for future production and other matters are included below. The Report is based on data supplied by the Company and on Netherland Sewell's opinions of reasonable practice in the industry. All evaluations of future revenue are after the deduction of future income tax expenses (unless otherwise noted in the tables) royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of Compton's reserves. There is no assurance that the forecast price and cost assumptions contained in the Netherland Sewell Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables. The recovery and reserves estimates on Compton's properties described herein are estimates only. The actual reserves on Compton's properties may be greater or less than those calculated. Compton has no heavy oil reserves and "crude oil" refers to light and medium crude oil only. This statement is dated March 23, 2005. The information being provided in this statement has an effective date of December 31, 2004 and a preparation date of March 1, 2005. CONSTANT PRICE AND COST The following table provides a summary of the Company's reserves by product type, based upon constant price and cost assumptions, before and after applicable royalties, excluding the Alberta Royalty Tax Credit ("ARTC"), at the end of the most recent fiscal year.
SUMMARY OF OIL AND GAS RESERVES USING CONSTANT PRICING AS OF DECEMBER 31, 2004 --------------------------------------------------------------------------------------------------------------------- CRUDE OIL NATURAL GAS (1) NGLS SULPHUR GROSS NET GROSS NET GROSS NET GROSS NET RESERVES CATEGORY (MBBL) (MBBL) (MCF) (MCF) (MBBL) (MBBL) (LONG TON) (LONG TON) --------------------------------------------------------------------------------------------------------------------- PROVED Developed producing 8,675 7,973 361,536 292,306 6,986 4,988 1,484 1,305 Developed non-producing 966 861 32,041 25,871 459 316 46 38 Undeveloped 2,815 2,231 51,845 41,798 1,309 959 121 101 --------------------------------------------------------------------------------------------------------------------- TOTAL PROVED 12,456 11,065 445,422 359,975 8,754 6,263 1,651 1,444 ---------------------------------------------------------------------------------------------------------------------
(1) The solution and associated gas represents 4% of the Company's natural gas reserves and therefore considered immaterial and is not broken out. The table set forth below summarizes the net present value of future net revenue as of December 31, 2004 based on constant price and cost assumptions. -15-
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2004 (CONSTANT PRICE) --------------------------------------------------------------------------------------------------------------------- NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)(1) BEFORE INCOME TAXES DISCOUNTED AFTER INCOME TAXES DISCOUNTED AT AT (%/YEAR) (%/YEAR) RESERVES CATEGORY 0% 10% 0% 10% --------------------------------------------------------------------------------------------------------------------- PROVED Developed producing $1,611,173 $ 795,299 $1,194,348 $598,552 Developed non-producing 169,942 87,609 126,523 65,772 Undeveloped 305,206 117,864 226,461 88,106 --------------------------------------------------------------------------------------------------------------------- TOTAL PROVED $2,086,321 $1,000,772 $1,547,332 $752,430 ---------------------------------------------------------------------------------------------------------------------
(1) A portion of the Company's reserves qualifies to receive the ARTC. The ARTC was assumed in the Report to continue under the current program or an extension thereof for a period of 10 years, but is not included in these numbers. Undiscounted total future net revenue calculated using constant prices and costs, incorporates the elements presented in the table below.
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2004 (CONSTANT PRICE) ---------------------------------------------------------------------------------------------------------------------- RESERVES REVENUE ROYALTIES OPERATING DEVELOPMENT WELL FUTURE NET INCOME FUTURE NET CATEGORY ($000S) ($000S) COSTS COSTS ABANDONMENT(1) REVENUE TAXES REVENUE ($000S) ($000S) COSTS ($000S) BEFORE ($000S) AFTER INCOME INCOME TAXES TAXES ($000S) ($000S) --------------------------------------------------------------------------------------------------------------------- Proved $3,960,838 $800,569 $971,392 $86,217 $16,340 $2,086,321 $538,989 $1,547,332 ----------------------------------------------------------------------------------------------------------------------
(1) Includes, at minimum, well abandonment costs (rather than total abandonment and reclamation costs). The following table summarizes the Company's total future net revenue using constant prices and costs, before income taxes, by production type.
TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2004 (CONSTANT PRICE) ---------------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY PRODUCTION TYPE FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED AT 10%/YEAR) ($000S) ---------------------------------------------------------------------------------------------------------------------- Proved Crude Oil, incl. solution gas and related ngls $199,414 Natural Gas and ngls, excl. solution gas and ngls $801,358 ----------------------------------------------------------------------------------------------------------------------
-16- FORECAST PRICE AND COST A summary of the Company's reserves by product type based upon forecast price and cost assumptions, before and after applicable royalties, excluding ARTC, 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, 2004 ---------------------------------------------------------------------------------------------------------------------- CRUDE OIL NATURAL GAS NGLS SULPHUR GROSS NET GROSS NET GROSS NET GROSS NET RESERVES CATEGORY (MBBL) (MBBL) (MCF) (MCF) (MBBL) (MBBL) (LONG TON) (LONG TON) ---------------------------------------------------------------------------------------------------------------------- PROVED Developed producing 8,577 7,915 360,534 291,472 6,979 4,982 1,485 1,306 Developed non-producing 967 865 31,924 25,774 458 316 46 39 Undeveloped 2,815 2,238 51,828 41,783 1,310 958 121 100 ---------------------------------------------------------------------------------------------------------------------- TOTAL PROVED 12,359 11,018 444,286 359,029 8,747 6,256 1,652 1,445 PROBABLE 7,908 6,669 206,072 168,808 4,830 3,520 888 791 ---------------------------------------------------------------------------------------------------------------------- TOTAL PROVED PLUS PROBABLE 20,267 17,687 650,358 527,837 13,577 9,776 2,540 2,236 ----------------------------------------------------------------------------------------------------------------------
The tables set forth below summarize the net present value of future net revenue as of December 31, 2004 based on forecast prices and cost assumptions.
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2004 (FORECAST PRICE) ---------------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY NET PRESENT VALUES OF FUTURE NET REVENUE ($000S) BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR) 0% 5% 10% 15% 20% ---------------------------------------------------------------------------------------------------------------------- PROVED Developed producing $1,645,719 $1,001,322 $ 748,371 $ 614,778 $530,423 Developed non-producing 162,566 107,836 81,164 65,611 55,346 Undeveloped 289,341 162,054 103,900 72,177 52,646 ---------------------------------------------------------------------------------------------------------------------- TOTAL PROVED 2,097,626 1,271,212 933,435 752,566 638,415 PROBABLE 1,002,855 571,281 370,710 259,057 189,294 ---------------------------------------------------------------------------------------------------------------------- TOTAL PROVED PLUS PROBABLE $3,100,481 $1,842,493 $1,304,145 $1,011,623 $827,709 ----------------------------------------------------------------------------------------------------------------------
-17- ---------------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY NET PRESENT VALUES OF FUTURE NET REVENUE ($000S) AFTER INCOME TAXES DISCOUNTED AT (%/YEAR) 0% 5% 10% 15% 20% ---------------------------------------------------------------------------------------------------------------------- PROVED Developed producing $1,219,655 $ 774,602 $573,874 $466,534 $400,169 Developed non-producing 121,607 81,571 61,645 50,051 42,452 Undeveloped 215,648 122,578 79,024 55,355 40,847 ---------------------------------------------------------------------------------------------------------------------- TOTAL PROVED 1,556,910 978,751 714,543 571,940 483,468 PROBABLE 689,748 381,960 234,895 153,799 103,786 ---------------------------------------------------------------------------------------------------------------------- TOTAL PROVED PLUS PROBABLE $2,246,658 $1,360,711 $949,438 $725,739 $587,254 ----------------------------------------------------------------------------------------------------------------------
Undiscounted total future net revenue calculated using forecast prices and costs and incorporates the elements presented in the table below.
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2004 ---------------------------------------------------------------------------------------------------------------------- RESERVES REVENUE ROYALTIES OPERATING DEVELOPMENT WELL FUTURE NET INCOME FUTURE NET CATEGORY ($000S) ($000S) COSTS COSTS ABANDON-MENT REVENUE TAXES REVENUE ($000S) ($000S) COSTS(1) BEFORE ($000S) AFTER ($000S) INCOME INCOME TAXES TAXES ($000S) ($000S) ---------------------------------------------------------------------------------------------------------------------- Proved $4,108,221 $ 817,944 $1,086,168 $ 86,877 $19,606 $2,097,626 $540,717 $1,556,910 Proved plus $6,028,292 $ 1,185,987 $1,347,280 $368,148 $26,396 $3,100,482 $853,823 $2,246,658 probable ----------------------------------------------------------------------------------------------------------------------
(1) Includes, at minimum, well abandonment costs (rather than total abandonment and reclamation costs). The following table summarizes the Company's total future net revenue using forecast price and cost assumptions, before income taxes, by production type.
TOTAL FUTURE NET REVENUE BY PRODUCTION TYPE AS OF DECEMBER 31, 2004 ---------------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY PRODUCTION TYPE FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED AT 10%/YEAR) ($000S) ---------------------------------------------------------------------------------------------------------------------- Proved Crude Oil, incl. solution gas and related ngls $ 187,641 Natural Gas and ngls, excl. solution gas and ngls $ 745,794 Proved plus probable Crude Oil, incl. solution gas and related ngls $ 269,747 Natural Gas and ngls, excl. solution gas and ngls $1,034,398 ----------------------------------------------------------------------------------------------------------------------
-18- PRICING ASSUMPTIONS CONSTANT PRICES USED IN ESTIMATES The constant price assumptions presume the continuance of current laws, regulations and operating costs in effect on the date of the Report. Future net revenue calculated using constant prices and costs is based upon the price assumptions set out below. The prices are founded upon the assumptions made by the independent engineering firm, Netherland Sewell, as of December 31, 2004. SUMMARY OF CONSTANT PRICING ASSUMPTIONS AS OF DECEMBER 31, 2004 ----------------------------------------------------------------------------------------------------------------------- CRUDE OIL NATURAL GAS NGLS SULPHUR YEAR EDMONTON PAR 400 AECO-C SPOT PROPANE BUTANE PENTANES+ PLANT GATE API ($CDN/BBL) ($CDN/MMBTU) ($CDN/BBL) ($CDN/BBL) ($CDN/BBL) ($CDN/LONG TON) ----------------------------------------------------------------------------------------------------------------------- Dec. 31, 2004 $45.69 $6.78 $35.77 $42.12 $48.96 $19.79 -----------------------------------------------------------------------------------------------------------------------
FORECAST PRICES USED IN ESTIMATES Future net revenue calculated using forecast prices and costs is based upon the price assumptions set out below. As an independent reserves evaluator, Netherland Sewell does not provide price forecasts. The average of December 31, 2004 pricing forecasts prepared by four major Canadian consulting firms were utilized in estimating Compton's reserves data using forecast pricing and costs. SUMMARY OF FORECAST PRICING AND INFLATION RATE ASSUMPTIONS AS OF DECEMBER 31, 2004 ----------------------------------------------------------------------------------------------------------------------- YEAR CRUDE OIL NATURAL GAS NGLS SULPHUR EDMONTON PAR AECO-C SPOT PROPANE BUTANE PENTANES+ PLANT GATE INFLATION 400 API ($CDN/MCF) ($CDN/BBL) ($CDN/BBL) ($CDN/BBL) ($CDN/LONG TON) RATE (1) ($CDN/BBL) %/YEAR ----------------------------------------------------------------------------------------------------------------------- FORECAST 2005 $50.63 $6.76 $32.43 $38.21 $51.90 $34.67(2) 0.75% 2006 $48.06 $6.53 $30.84 $35.82 $49.30 $24.60 0.75% 2007 $44.99 $6.33 $28.97 $33.62 $46.17 $15.65 0.75% 2008 $42.33 $6.01 $27.33 $31.63 $43.47 $14.06 0.75% 2009 $40.63 $5.83 $26.22 $30.40 $41.73 $14.57 0.75% 2010 $39.91 $5.74 $25.74 $29.81 $41.00 $15.25 0.75% 2011 $40.48 $5.85 $26.14 $30.23 $41.58 $15.77 0.75% 2012 $41.07 $5.94 $26.50 $30.70 $42.21 $16.45 0.75% 2013 $41.76 $6.03 $26.93 $31.18 $42.92 $16.97 0.75% 2014 $42.54 $6.16 $27.42 $31.81 $43.71 $17.67 0.75% 2015 $43.25 $6.28 $27.94 $32.32 $44.44 $18.20 0.75% Thereafter 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 0.75% -----------------------------------------------------------------------------------------------------------------------
(1) Inflation rates for forecasting operating costs and capital investments. (2) A price of $9.00/LT was used in the first 6 months of 2005 to reflect the contract price. The weighted average realized sale price for Compton for the year ended December 31, 2004 was $6.46/mcf for natural gas, $46.79/bbl for crude oil, $37.91/bbl for ngls and $26.25/long ton for sulphur. -19- RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE RESERVES RECONCILIATION The following table provides a summary of the changes in the Company's reserves which occurred in the most recent fiscal year, based upon escalated price and cost assumptions, net of applicable royalties.
RECONCILIATION OF NET RESERVES BY PRODUCT TYPE USING FORECAST PRICES AND COSTS(1) ---------------------------------------------------------------------------------------------------------------------- CRUDE OIL NGLS NET NET NET PROVED NET NET NET PROVED PLUS PROVED PROBABLE PLUS PROBABLE PROVED PROBABLE PROBABLE (MBBL) (MBBL) (MBBL) (MBBL) (MBBL) (MBBL) ---------------------------------------------------------------------------------------------------------------------- December 31, 2003 8,163 2,016 10,179 4,573 2,142 6,715 Extensions - 4,579 4,579 - 1,713 1,713 Improved recovery 1,116 38 1,154 2,957 355 3,312 Technical revisions 1,705 (136) 1,569 (1,563) (852) (2,415) Discoveries 933 172 1,105 489 154 643 Acquisitions 252 - 252 160 8 168 Dispositions - - - - - - Production (1,151) - (1,151) (360) - (360) ---------------------------------------------------------------------------------------------------------------------- December 31, 2004 11,018 6,669 17,687 6,256 3,520 9,776 ----------------------------------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------------------------------- NATURAL GAS SULPHUR NET NET NET PROVED NET NET NET PROVED PROVED PROBABLE PLUS PROBABLE PROVED PROBABLE PLUS PROBABLE (MMCF) (MMCF) (MMCF) (LONG TON) (LONG TON) (LONG TON) ---------------------------------------------------------------------------------------------------------------------- December 31, 2003 324,955 135,347 460,302 1,623 718 2,341 Extensions - 75,137 75,137 - - - Improved recovery 19,633 22 19,655 - - - Technical revisions 16,359 (48,574) (32,215) (109) 73 (36) Discoveries 28,057 5,702 33,759 - - - Acquisitions 8,562 1,174 9,736 - - - Dispositions (1,395) - (1,395) - - - Production (37,142) - (37,142) (69) - (69) ---------------------------------------------------------------------------------------------------------------------- December 31, 2004 359,029 168,808 527,837 1,445 791 2,236 ----------------------------------------------------------------------------------------------------------------------
(1) Prepared by Management. -20- FUTURE NET REVENUE RECONCILIATION The following table reconciles changes between the future net revenue estimates at December 31, 2004 and the corresponding estimates in the prior year, using constant prices and costs, discounted at 10%.
RECONCILIATION OF CHANGES IN NET PRESENT VALUE AT 10% OF FUTURE NET REVENUE OF PROVED RESERVES (1) --------------------------------------------------------------------------------------------------------------------- 2004 ($000S) (2) --------------------------------------------------------------------------------------------------------------------- Estimated future net revenue at beginning of year $ 759,083 Sales and transfers of oil and gas produced, net of production costs and royalties (226,354) Net changes in prices, production costs and royalties related to future production 174,387 Changes in previously estimated development costs incurred during the period (149,188) Changes in estimated future development costs (54,838) Extensions and improved recovery 57,634 Discoveries 103,472 Acquisitions of reserves (7,749) Dispositions of reserves 4,416 Net change resulting from revisions in quantity estimates 306,271 Accretion of discount 75,908 Net change in income taxes(3) (42,270) --------------------------------------------------------------------------------------------------------------------- Estimated future net revenue at end of year $1,000,772 ---------------------------------------------------------------------------------------------------------------------
(1) Prepared by Management. (2) Except for "Net Change in Income Taxes", the amounts above are before tax. (3) Includes both income taxes incurred during the period and changes in estimated future income tax expenses. ADDITIONAL INFORMATION RELATING TO RESERVES DATA UNDEVELOPED RESERVES The following discussion generally describes the basis on which Compton attributes proved and probable undeveloped reserves and its plans for developing those undeveloped reserves. PROVED UNDEVELOPED RESERVES Proved undeveloped reserves are generally those reserves related to wells that have been tested and not yet tied-in, wells drilled near the end of the fiscal year or wells further away from the Company's gathering systems. In addition, such reserves may relate to planned infill drilling locations. The majority of these reserves are planned to be on stream within a two year timeframe. 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 on stream within a two year timeframe. SIGNIFICANT FACTORS OR UNCERTAINTIES AFFECTING RESERVES DATA The process of estimating reserves is complex. 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 -21- economic conditions impacting oil and natural gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. Compton's reserves are evaluated by Netherland Sewell. As circumstances change and additional data becomes available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and natural gas prices, and reservoir performance. Such revisions can be either positive or negative. FUTURE DEVELOPMENT COSTS The following table provides a summary of the development costs deducted in the estimation of future net revenue attributable to each of the following reserves categories: DEVELOPMENT COSTS DEDUCTED IN ESTIMATING FUTURE NET REVENUES (1)
--------------------------------------------------------------------------------------------------------------------- YEAR PROVED PROVED PLUS PROBABLE CONSTANT PRICES AND FORECAST PRICES AND FORECAST PRICES AND COSTS/YEAR ($000S) COSTS/YEAR ($000S) COSTS/YEAR ($000S) --------------------------------------------------------------------------------------------------------------------- Undiscounted 2005 $ 47,541 $ 47,583 $165,087 2006 25,330 25,612 141,028 2007 6,692 6,882 38,920 2008 7,184 7,375 20,709 2009 801 939 3,861 Remaining 15,009 18,092 24,939 --------------------------------------------------------------------------------------------------------------------- Total undiscounted $102,557 $106,483 $394,544 Total discounted at 10% per year $ 81,648 $ 82,864 $332,436 ---------------------------------------------------------------------------------------------------------------------
(1) Includes abandonment costs. 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 expects to fund its total 2005 capital program with internally generated cash flow, equity, bank debt and minor property dispositions. -22- OIL AND GAS PROPERTIES AND WELLS The following table summarizes the location of the Company's interests as at December 31, 2004, in crude oil and natural gas wells which are producing or which the Company considers to be capable of production.
--------------------------------------------------------------------------------------------------------------------- AREA PRODUCING SHUT-IN CRUDE PRODUCING SHUT-IN TOTAL CRUDE OIL OIL WELLS NATURAL GAS NATURAL GAS WELLS WELLS WELLS GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET --------------------------------------------------------------------------------------------------------------------- ALBERTA South 79 32 14 6 508 409 24 17 625 464 Central 104 19 17 4 402 132 81 32 604 187 Peace River Arch 230 144 64 31 115 50 47 22 456 247 BC 4 - - - 41 3 6 - 47 3 --------------------------------------------------------------------------------------------------------------------- TOTAL WELLS 417 195 95 41 1,066 594 158 72 1,732 902 ---------------------------------------------------------------------------------------------------------------------
PROPERTIES WITH NO ATTRIBUTED RESERVES The following table sets forth the Company's undeveloped land holdings to which no proved reserves have been attributed as at December 31, 2004.
--------------------------------------------------------------------------------------------------------------------- AREA GROSS ACRES NET ACRES --------------------------------------------------------------------------------------------------------------------- British Columbia 32,302 3,829 Alberta 979,333 717,781 Manitoba 8,219 7,819 --------------------------------------------------------------------------------------------------------------------- TOTAL 1,019,854 729,429 ---------------------------------------------------------------------------------------------------------------------
Approximately 113,638 net acres of undeveloped land could expire by December 31, 2005. However, the Company's 2005 exploration and development activities may defer the expiry of a portion of these lands. Compton has approximately $54 million of work commitments associated with unproved properties. FORWARD CONTRACTS In 2004, Compton's realized average field price was $39.82/boe, comprised of $6.46/mcf for natural gas and $43.21/bbl for liquids (crude oil and ngls). In 2003, the average field prices of natural gas and liquids were $6.01/mcf and $34.39/bbl, respectively, for an average price of $35.66/boe. Compton's natural gas production is sold under a combination of longer term contracts with aggregators and short term daily or 30 day AECO indexed contracts. Approximately 12% of the Company's natural gas production in 2004 was committed to aggregators. The average aggregator price realized was approximately $0.32/mcf less than the non-aggregator prices realized during the year. Compton's crude oil sales are priced at Edmonton postings and are typically sold on 30 day evergreen arrangements. Ngls are bid out on an annual basis to establish the most competitive pricing. The Company sells crude oil and ngls primarily to refineries and marketers of crude oil and ngls. From time to time, Compton may enter into hedging arrangements to mitigate commodity price risk and take advantage of opportunistic pricing. In accordance with Compton's policy, hedging programs will not exceed 50% of non-contracted production. -23- ADDITIONAL INFORMATION CONCERNING ABANDONMENT AND RECLAMATION COSTS Compton is required to remove production equipment, batteries, pipelines and natural gas plants and to restore land at the end of oil and natural gas operations. The Company estimates these costs in accordance with existing laws, contracts and other policies. These obligations are initially measured at fair value, which is the discounted future value of the liability. This fair value is also capitalized as part of the cost of the related assets and amortized over the useful life of the assets. An independent environmental consulting firm was hired to assist Management in the estimation of the Company's asset retirement obligations ("ARO"). ARO cost calculations were derived from a combination of actual third party cost quotes, EUB cost models and typical industry experience and practices. The deemed ARO liability for Compton's 1,175 net well sites and facilities is the sum of the calculated abandonment and reclamation liabilities adjusted for designated status as active, inactive, abandoned or problem site. Information regarding environmental remediation costs and other liability issues for site specific concerns were derived from a review of historical audit and assessment reports of sites and facilities. An inflation rate of 2.0% and a credit adjusted risk free rate of 10.8% was used in the fair value calculation. Total asset retirement costs, net of estimated salvage values, is $68 million or $11 million when discounted at 10%. The undiscounted ARO associated with pipelines and facilities is $45 million and is not deducted in estimating total future net revenue, as calculated in the Company's reserve report. The Company expects to pay $1 million dollars in ARO costs between 2005 and 2008. TAX HORIZON Based upon planned capital expenditure programs and current commodity price assumptions, the Company will not be cash taxable until 2007. CAPITAL EXPENDITURES In 2004, Compton incurred $77 million of exploration costs and $196 million of development costs. Additionally, $13 million was spent on proved property acquisitions and $13 million was spent on unproved property acquisitions. EXPLORATION AND DEVELOPMENT ACTIVITIES The following table sets forth the number of crude oil, natural gas and service wells drilled by the Company, or which the Company participated in drilling, that are capable of production, as well as the number of dry and abandoned wells, all expressed in terms of gross and net wells during the years ended December 31, 2004 and 2003. Eight wells drilled in 2004 are standing cased wells and are awaiting completion and testing. These wells are not included in the following table.
--------------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2004 YEAR ENDED DECEMBER 31, 2003 DEVELOPMENT EXPLORATORY DEVELOPMENT EXPLORATORY GROSS NET GROSS NET GROSS NET GROSS NET --------------------------------------------------------------------------------------------------------------------- Natural Gas 106 88 6 3 67 46 48 45 Crude Oil 22 14 28 23 17 11 1 1 Dry and Abandoned 10 7 6 5 9 8 19 18 --------------------------------------------------------------------------------------------------------------------- TOTAL 143 112 43 34 93 65 68 64 SUCCESS RATIO 90% 91% ---------------------------------------------------------------------------------------------------------------------
-24- In 2005, the Company will continue to focus its resources in Alberta, Canada. Compton's overall objective for 2005 is the recognition of its unbooked resource potential. The Company has developed an aggressive $390 million capital expenditures plan for 2005, encompassing up to 390 gross wells. PRODUCTION HISTORY The Company's average daily production volume of natural gas and liquids (crude oil and ngls), before deduction of royalties, for each of the periods indicated, is set forth below. GROSS NATURAL GAS AND LIQUIDS (CRUDE OIL AND NGLS) PRODUCTION --------------------------------------------------------------------------------------------------------------------- PRODUCT TYPE FISCAL 2004 THREE MONTHS ENDED MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, TOTAL 2004 2004 2004 2004 2004 --------------------------------------------------------------------------------------------------------------------- Natural gas (mmcf/d) 120 122 123 127 123 Natural gas (mmcf) 10,954 11,094 11,347 11,725 45,120 Liquids (crude oil & ngls) (boe/d) 5,655 5,977 6,712 6,963 6,330 Liquids (crude oil & ngls) (mbbls) 515 544 618 640 2,317 ---------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------- PRODUCT TYPE FISCAL 2003 THREE MONTHS ENDED MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, TOTAL 2004 2004 2004 2004 2004 --------------------------------------------------------------------------------------------------------------------- Natural gas (mmcf/d) 119 119 111 123 118 Natural gas (mmcf) 10,684 10,783 10,217 11,302 42,986 Liquids (crude oil & ngls) (boe/d) 6,068 5,910 5,710 6,010 5,924 Liquids (crude oil & ngls) (mbbls) 546 538 525 553 2,162 ---------------------------------------------------------------------------------------------------------------------
2005 PRODUCTION ESTIMATES Production volumes in 2005 as estimated in the reserve forecast before deduction of royalties are set forth below. Production volumes are the same in both the constant price case and the forecast price cases.
--------------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY CRUDE OIL NATURAL GAS LIQUIDS SULPHUR (LONG (BBL/D) (MMCF/D) (BBL/D) TON/D) --------------------------------------------------------------------------------------------------------------------- PROVED Developed producing 3,098 86 1,615 157 Developed non-producing 421 11 152 1 Undeveloped 181 7 132 10 --------------------------------------------------------------------------------------------------------------------- TOTAL PROVED 3,700 104 1,899 168 PROBABLE 1,253 22 251 33 --------------------------------------------------------------------------------------------------------------------- TOTAL PROVED PLUS PROBABLE 4,953 126 2,150 201 ---------------------------------------------------------------------------------------------------------------------
-25- The Company's field netbacks for natural gas and liquids (crude oil and ngls), for each of the periods indicated, is set forth below.
NATURAL GAS AND LIQUIDS (CRUDE OIL AND NGLS) FIELD NETBACKS --------------------------------------------------------------------------------------------------------------------- FISCAL 2004 THREE MONTHS ENDED TOTAL MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, 2004 2004 2004 2004 2004 --------------------------------------------------------------------------------------------------------------------- NATURAL GAS ($/MCF) Revenue price (1) $6.25 $6.84 $6.48 $6.29 $6.46 Royalties, net (1.48) (1.57) (1.64) (1.64) (1.58) Operating costs (0.91) (0.92) (0.93) (1.01) (0.94) Transportation costs (0.14) (0.14) (0.13) (0.16) (0.15) --------------------------------------------------------------------------------------------------------------------- Field netback $3.72 $4.21 $3.78 $3.48 $3.79 LIQUIDS (CRUDE OIL & NGLS) ($/BBL) Revenue price (1) $40.03 $42.75 $46.60 $42.88 $43.21 Royalties, net (8.88) (9.40) (9.82) (9.82) (9.50) Operating costs (5.46) (5.51) (5.59) (6.05) (5.66) Transportation costs (0.84) (0.86) (0.81) (0.98) (0.87) --------------------------------------------------------------------------------------------------------------------- Field netback $24.85 $26.98 $30.38 $26.03 $27.18 ---------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------- FISCAL 2003 THREE MONTHS ENDED TOTAL MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, 2003 2003 2003 2003 2003 --------------------------------------------------------------------------------------------------------------------- NATURAL GAS ($/MCF) Revenue price (1) $7.24 $6.36 $5.84 $5.67 $6.27 Royalties, net (1.64) (1.49) (1.38) (1.39) (1.48) Operating costs (2) (0.87) (0.92) (0.97) (0.82) (0.89) Transportation costs (0.15) (0.15) (0.15) (0.15) (0.15) --------------------------------------------------------------------------------------------------------------------- Field netback $4.58 $3.80 $3.34 $3.31 $3.75 LIQUIDS (CRUDE OIL & NGLS) ($/BBL) Revenue price (1) $38.40 $34.41 $35.15 $34.37 $35.59 Royalties, net (9.85) (8.95) (8.29) (8.33) (8.85) Operating costs (2) (5.21) (5.54) (5.79) (4.90) (5.35) Transportation costs (0.91) (0.92) (0.90) (0.90) (0.91) --------------------------------------------------------------------------------------------------------------------- Field netback $22.43 $19.00 $20.17 $20.24 $20.48 --------------------------------------------------------------------------------------------------------------------- (1) 2003 revenue prices have been restated to exclude realized hedge losses and transportation charges. (2) 2003 operating costs have been restated to exclude transportation charges.
-26- DIVIDENDS The Company has neither declared nor paid any dividends on its common shares. The Company intends to retain its earnings to finance growth and expand its operations and does not anticipate paying any dividends on its common shares in the foreseeable future. CAPITAL STRUCTURE Compton is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares, of which 127,071,986 common shares are issued and outstanding as fully paid and non-assessable share as at March 23, 2005. No preferred shares are issued and outstanding as at March 23, 2005. The following is a description of Company's common and preferred shares. COMMON SHARES Common shares have attached to them the following rights, privileges, restrictions and conditions: (i) except for meetings at which only holders of another specified class or series of shares of the Company are entitled to vote separately as a class or series, each holder of a common share is entitled to receive notice of, to attend and to vote at all meetings of the shareholders of the Company; (ii) subject to the rights, privileges, restrictions and conditions attached to any preferred shares, the holders of common shares are entitled to receive dividends if, and when declared by the Directors of the Company; and (iii) subject to the rights, privileges, restrictions and conditions attached to any other class of shares of the Company, the holders of common shares are entitled to share equally in the remaining property of the Company upon liquidation, dissolution or winding-up of the Company. PREFERRED SHARES The preferred shares may be issued in one or more series, and the Directors are authorized to fix the number of shares in each series and to determine the designation, rights, privileges, restrictions and conditions attached to the shares of each series. The preferred shares are entitled to a priority over the common shares with respect to the payment of dividends and the distribution of assets upon the liquidation, dissolution or winding-up of Compton. SHAREHOLDER RIGHTS PLAN Compton has a shareholder rights plan (the "Rights Plan") under the terms of a shareholder rights plan agreement dated as of April 22, 2003 between 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. -27- MARKET FOR SECURITIES The outstanding common shares of the Company are listed and posted for trading on the Toronto Stock Exchange under the symbol "CMT". Compton's common shares are included in the S&P/TSX Composite Index and the TSX Mid-Cap Index. The following table sets out the high and low closing prices and average trading volume of common shares as reported by the Toronto Stock Exchange, as applicable, for the periods indicated.
--------------------------------------------------------------------------------------------------------------------- PERIOD HIGH CLOSE LOW CLOSE AVERAGE DAILY TRADING VOLUME --------------------------------------------------------------------------------------------------------------------- 2004 January $ 5.98 $ 7.17 1,167,334 February $ 7.85 $ 6.86 871,891 March $ 8.28 $ 7.34 534,715 April $ 8.55 $ 7.45 829,296 May $ 7.74 $ 6.95 543,027 June $ 8.05 $ 7.25 452,574 July $ 8.40 $ 7.50 762,226 August $ 7.96 $ 7.35 376,988 September $ 9.06 $ 7.60 609,036 October $10.75 $ 9.35 772,762 November $11.25 $10.30 760,722 December $11.22 $10.16 444,202 2005 January $10.51 $11.65 516,574 February $11.46 $12.65 667,961 March 1-23 $13.74 $12.05 634,660 ---------------------------------------------------------------------------------------------------------------------
CONFLICTS OF INTEREST The Directors and Officers of Compton are engaged in and will continue to engage in other activities in the oil and natural gas industry and as a result of these and other activities, the Directors and Officers of Compton may become subject to conflicts of interest. The Business Corporations Act (Alberta) (the "ACT") provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided under the Act. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the Act. As at the date hereof, Compton is not aware of any existing or potential material conflicts of interest between Compton and a Director or Officer of the Company. INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS None of the current executive Officers or Directors of Compton, and no person or company owning or exercising control 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, direct or indirect, in any transaction or proposed transaction that has materially affected or would materially affect Compton. -28- 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 shares. As at the date hereof, principals of Netherland Sewell personally disclosed in certificates of qualification that they neither had, nor expected to receive, any of the Company's outstanding shares. RATINGS Standard & Poor's Rating Services and Moody's Corporation have rated Compton's U.S. denominated 9.9% senior notes as "B" and "B2" respectively, as at December 31, 2004. 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. DIRECTORS AND OFFICERS DIRECTORS Information is given below with respect to each of the current Directors of the Company. All Directors of Compton stand for election at each annual meeting of the Company. The next Annual and Special Meeting of Shareholders is scheduled for May 10, 2005 at 3:30 pm. (Calgary time) in the Chamber of Commerce, 517 - Centre Street South, Calgary, Alberta, Canada. The Board of Directors has established an Audit, Finance and Risk Committee, an Engineering, Operations and Reserves Committee, a Human Resources, Compensation, Environmental, Health and Safety Committee and a Corporate Governance Committee. Each of these Committees consists of all Directors of the Company, other than Mr. Sapieha, each of whom is an independent, outside and unrelated Director. The name, city of residence and principal occupation during the last five years of each of the Directors of the Company are set forth in the following table.
--------------------------------------------------------------------------------------------------------------------- NAME AND MUNICIPALITY OF PRINCIPAL OCCUPATION DIRECTOR SINCE RESIDENCE --------------------------------------------------------------------------------------------------------------------- Mel F. Belich, Q.C. Chairman and President of Enbridge International Inc. and Enbridge 1993 Calgary, Alberta Technology Inc., and Group Vice President - International and Corporate Law, Enbridge Inc., an energy transportation and distribution company. Mr. Belich is the Chairman of the Board of Directors of Compton and the Chairman of the Corporate Governance Committee. --------------------------------------------------------------------------------------------------------------------- Chairman and Chief Executive Officer, IKO Resources Inc., a petroleum Irvine J. Koop, P. Eng. consulting firm and prior thereto, President and CEO, Pipelines and 1996 Calgary, Alberta Midstream of Westcoast Energy Inc. Mr. Koop is the Chairman of the Human Resources, Compensation, Environmental, Health and Safety Committee. --------------------------------------------------------------------------------------------------------------------- John W. Preston Account Executive, Sun Microsystems of Canada Inc., a computer 1993 Calgary, Alberta company. ---------------------------------------------------------------------------------------------------------------------
-29-
--------------------------------------------------------------------------------------------------------------------- PRINCIPAL OCCUPATION NAME AND MUNICIPALITY OF DIRECTOR SINCE RESIDENCE --------------------------------------------------------------------------------------------------------------------- Ernest G. Sapieha, C.A. President & Chief Executive Officer of the Company. 1993 Calgary, Alberta --------------------------------------------------------------------------------------------------------------------- Jeffrey T. Smith, P. Geol. Independent Businessman and prior thereto, Chief Operating Officer of 1999 Calgary, Alberta Northstar Energy Corporation. Mr. Smith is Chairman of the Engineering, Reserves and Operations Committee. --------------------------------------------------------------------------------------------------------------------- John A. Thomson, C.A. Independent Businessman and prior thereto, Senior Vice President and 2003 Calgary, Alberta Chief Financial Officer of Renaissance Energy Ltd. Mr. Thomson is the Chairman of the Audit, Finance and Risk Committee. ---------------------------------------------------------------------------------------------------------------------
Further information about the Directors and the committees of the Board of Directors is set forth under the heading "Election of Directors" on pages 1 to 3 of the Company's Management Proxy Circular dated March 4, 2005 relating to the Annual and Special Meeting of Shareholders to be held on May 10, 2005, which sections are incorporated by reference into this Annual Information Form. OFFICERS The name, city of residence and principal occupation during the last five years of each of the Officers of the Company are set forth in the following table.
--------------------------------------------------------------------------------------------------------------------- NAME AND MUNICIPALITY OF RESIDENCE PRINCIPAL OCCUPATION --------------------------------------------------------------------------------------------------------------------- Ernie G. Sapieha, C.A. President & Chief Executive Officer of the Company. Calgary, Alberta Norman G. Knecht, C.A. Vice President Finance & Chief Financial Officer of the Company. Calgary, Alberta Tim G. Millar, LL.B. Vice President, General Counsel & Corporate Secretary of the Company; prior Calgary, Alberta to 2003, Senior Partner of Fraser Milner Casgrain LLP, Barristers and Solicitors. Murray J. Stodalka, P. Eng. Vice President, Operations & Engineering of the Company. Calgary, Alberta Kim N. Davies, P.Geoph. Vice President, New Ventures, prior to 2003, Vice President, Exploration of Calgary, Alberta the Company. Marc R. Junghans, P. Geol. Vice President, Exploration, prior to 2002, Manager of Exploration of the Calgary, Alberta Company. ---------------------------------------------------------------------------------------------------------------------
As at March 23, 2005, the Directors and officers of Compton as a group beneficially owned or controlled, directly or indirectly, 11,193,060 common shares of Compton, representing approximately 8.8% of the issued and outstanding common shares of the Company. None of the Directors or Officers held a sufficient number of common shares to materially affect the control of Compton. -30- AUDIT, FINANCE AND RISK COMMITTEE INFORMATION The Charter of the Audit, Finance and Risk Committee is set forth in Schedule C. COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE Chairman: John A. Thomson Members: Mel F. Belich, Irvine J. Koop, John W. Preston and Jeffrey T. Smith All members of the Audit, Finance and Risk Committee are independent, unrelated, outside Directors. An "independent" director is a director who has no direct or indirect material relationship with the Company (a material relationship is a relationship which could, in the view of the Board, reasonably interfere with the exercise of a director's independent judgment). An "unrelated" Director is a director who is (a) not a member of Management and is free from any interest and any business, family or other relationship which could, or could reasonably be perceived to, materially interfere with the Director's ability to act with a view to the best interests of the Company, other than interests and relationships arising from shareholding, (b) not currently or has not been, within the last three years, an officer, employee of or material service provider to the Company or any of its subsidiaries or affiliates, and (c) not a director, officer employee or significant shareholder of an entity that has a material business relationship with the Company. An "outside" Director is not a member of the Company's Management. Additionally, no Board members sit on other boards together, in order that there are no inter-related interests. Mr. Thomson is considered to be a "financial expert", as defined in National Instrument 52-110, due to his experience in the oil and natural gas industry as a Chartered Accountant, as Chief Financial Officer of a major public oil and natural gas company, and as a board member and Officer for other public reporting oil and natural gas companies. All other Committee members are "financially literate", as defined in National Instrument 52-110. EXTERNAL AUDITOR FEES The aggregate amounts paid or accrued by the Company with respect to fees payable to Grant Thornton LLP for audit and audit-related (including separate audits of subsidiary entities, financings and regulatory reporting requirements), tax and other services in the fiscal years ended December 31, 2004 and 2003 were as follows: --------------------------------------------------------------------------------------------------------------------- TYPE OF SERVICE FISCAL 2004 FISCAL 2003 --------------------------------------------------------------------------------------------------------------------- Audit $273,270 $239,558 Audit Related 131,315 78,490 Tax 7,500 7,970 Other Non-Audit 53,848 29,350 --------------------------------------------------------------------------------------------------------------------- Total $465,933 $355,368 ---------------------------------------------------------------------------------------------------------------------
The audit related fees incurred in fiscal 2004 related to discussions regarding the accounting treatment for MPP. Tax fees incurred in fiscal 2004 related to the review of tax forms and the fees for other non-audit services in fiscal 2004 were incurred to translate the Company's quarterly and annual reports into French and discussions regarding requirements of the Sarbanes-Oxley Act. The audit related fees incurred in fiscal 2003 related to the issuance of the Company's U.S. dollar senior term notes in May 2002 as well as accounting policy and research discussions. Tax fees incurred in fiscal 2003 related to the review of tax forms and the fees for other non-audit services in fiscal 2003 were incurred to translate the Company's quarterly and annual reports into French. -31- The Audit, Finance and Risk Committee of the Company considered these fees and determined that they were reasonable and do not impact the independence of the Company's auditors. Further, such Committee determined that in order to ensure the continued independence of the auditors, only limited non-audit related services would be provided to the Company by Grant Thornton LLP and in such case, only with the prior approval of the Audit, Finance and Risk Committee. The Committee has pre-approved Management to retain Grant Thornton LLP to provide miscellaneous, minor, non-audit services in circumstances where it is not feasible or practical to convene a meeting of the Audit, Finance and Risk Committee, subject to an aggregate limit of $20,000 per quarter. TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for the Company's shares is Computershare Trust Company of Canada at its office in Calgary, Alberta. RISK FACTORS Compton's operations are subject to risks normally associated with the oil and natural gas industry. The most important of these are set out below, together with the strategies Compton employs to mitigate and minimize these risks. INHERENT INDUSTRY RISK THAT EXPLORATION AND DEVELOPMENT PROGRAMS MAY NOT RESULT IN ECONOMIC RESERVE ADDITIONS TO REPLACE PRODUCTION. Compton's strategies to minimize this inherent risk include focusing on selected core areas in Western Canada with high working interests and assuming operatorship of key facilities. The Company utilizes a team of highly qualified professionals with expertise and experience in these areas. Compton assesses strategic acquisitions to complement existing activities while striving for a balance between exploration and lower risk development and exploitation prospects. FINANCIAL RISKS INCLUDING COMMODITY PRICES AND EXPENDITURE COSTS SHIFTING DUE TO CHANGES IN MARKET CONDITIONS. Commodity prices are driven by supply, demand and market forces outside the Company's influence. However, the Company's product mix is diversified to reduce exposure to any one commodity's price movements. Sales of oil and natural gas are aimed at various markets to avoid undue exposure to any one market. When appropriate, Compton ensures that parental guarantees or letter of credit are in place to minimize the impact in the event of default. Compton monitors and focuses its expenditures to reflect price and production changes. Compton continuously scrutinizes market conditions and opportunities. From time to time, the Company will employ financial instruments to manage exposure related to Canada/U.S. dollar exchange rates and commodity prices. The Company has commodity and fixed price contracts outstanding. The Company considers longer term contracts with suppliers, where appropriate, to mitigate shifts in costs resulting from changes in industry and market conditions. Compton has no control over government intervention or taxation levels on the industry. It is likely that in the future the Company will be required to raise additional capital via debt and/or equity financings in order to fully realize its strategic goals and business plans. Compton's ability to raise additional capital will depend upon a number of factors, such as general economic and market conditions that are beyond its control. If Compton is unable to obtain additional financing or to obtain it on favorable terms, the Company might be required to forego attractive business opportunities. Compton is committed to maintaining a strong balance sheet, combined with a flexible capital expenditure program that can be adjusted to capitalize on or reflect acquisition opportunities or a tightening of liquidity sources. MECHANICAL AND OPERATIONAL RISKS ASSOCIATED WITH THE DRILLING FOR, PRODUCTION AND PROCESSING OF NATURAL GAS AND CRUDE OIL, INCLUDING DAMAGE TO THE COMPANY'S EQUIPMENT AND THE LIABILITY ASSOCIATED WITH AN OCCURRENCE OR MALFUNCTION. Compton manages operational risks by employing skilled professionals utilizing leading edge technology and conducting regular maintenance and training programs. The Company has both an operational emergency response plan and an operational safety manual. In addition, a comprehensive insurance program is maintained to mitigate risks and protect against significant losses where possible. -32- Compton operates in accordance with all applicable environmental legislation. The Company strives to maintain or surpass compliance with such regulations and works with government agencies, landholders and other parties to minimize the environmental impact of its activities. Compton is also subject to various government-imposed regulatory risks, some of which are beyond the Company's control. Compton has established an Engineering, Reserves and Operations Committee to ensure that employees and the environment are protected while the Company is engaged in its exploration and development activities. Policies and procedures have been established to ensure environmental protection standards are maintained and standards of operating practice are designed to minimize risk to employees and the environment. ADDITIONAL INFORMATION Additional information including Directors' and Officers' remuneration and indebtedness, principal holders of the Company's common shares, options to acquire common shares and interests of insiders in material transactions (if applicable) is contained in the Management Proxy Circular issued by Management dated March 4, 2005, relating to the Annual and Special Meeting of Shareholders to be held on May 10, 2005. Additional financial information is also provided in the consolidated financial statements of the Company for the year ended December 31, 2004 included in the Company's 2004 Annual Report. Copies of these documents have been filed with the Canadian Securities Administrators' System for Electronic Document Analysis and Retrieval ("SEDAR") at www.sedar.com. Additional copies of this Annual Information Form are available to the public and may be obtained by contacting: Compton Petroleum Company Suite 3300, 425 - 1st Street S.W. Fifth Avenue Place, East Tower Calgary, Alberta, Canada T2P 3L8 Attention: Mr. Norman G. Knecht, C.A. Vice President Finance & Chief Financial Officer Telephone: (403) 237-9400 Fax: (403) 237-9410 -33- SCHEDULE A REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR To the Board of Directors of Compton Petroleum Corporation (the "COMPANY"): 1. We have evaluated the Company's reserves data as at December 31, 2004. The reserves data consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and (ii) the related estimated future net revenue; and (b) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and (ii) the related estimated future net revenue. 2. The reserves data are the responsibility of the Company's Management. Our responsibility is to express an opinion on the reserves data based on our evaluation. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE HANDBOOK") prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society). 3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook. 4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2004 and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company's Board of Directors:
Description and Net Present Value of Future Net Revenue (before Independent Qualified Preparation Date Location Canadian federal income taxes, 10% discount rate)(C$) Reserves Evaluator or of Evaluated of ---------------------------------------------------- Auditor Report Reserves Audited Evaluated Reviewed Total ----------------------- ------------------ ---------- --------- -------------- ------------ -------------- Netherland, Sewell & March 1, 2005 Canada nil 1,304,144,800 nil 1,304,144,800 Associates, Inc.
5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. 6. We have no responsibility to update our reports referred to in paragraph 4 for events and circumstances occurring after their respective preparation dates. -34- 7. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. Executed as to our report referred to above: NETHERLAND, SEWELL, & ASSOCIATES, INC. Dallas, Texas, USA March 14, 2004 By: /s/ Frederic D. Sewell ------------------------------------ Frederic D. Sewell Chairman and Chief Executive Officer -35- SCHEDULE B REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES ON OIL AND GAS DISCLOSURE Management of Compton Petroleum Corporation (the "COMPANY") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and (ii) the related estimated future net revenue; and (b) (i) proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and (ii) the related estimated future net revenue. An independent qualified reserves evaluator has evaluated the Company's reserves data. The report of the independent qualified reserves evaluator will be filed with securities regulatory authorities concurrently with this report. The Engineering, Reserves and Operations Committee of the Board of Directors of the Company has: (c) reviewed the Company's procedures for providing information to the independent qualified reserves evaluator; (d) 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 (e) reviewed the reserves data with Management and the independent qualified reserves evaluator. The Engineering, Reserves and Operations Committee of the Board of Directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with Management. The Board of Directors has, on the recommendation of the Engineering, Reserves and Operations Committee approved: (f) the content and filing with securities regulatory authorities of the reserves data and other oil and gas information; (g) the filing of the report of the independent qualified reserves evaluator on the reserves data; and (h) the content and filing of this report. -36- Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. /s/ Ernie Sapieha /s/ Murray Stodalka --------------------- ------------------------- Ernie Sapieha Murray Stodalka President & CEO Vice President Operations and Engineering /s/ Jeffrey Smith /s/ Mel Belich --------------------- ------------------------- Jeffrey Smith Mel Belich Chairman of the Engineering, Chairman of the Board Committee Reserves and Operations March 23, 2005 -37- SCHEDULE C CHARTER OF THE AUDIT, FINANCE AND RISK COMMITTEE MANDATE OF THE COMMITTEE ------------------------ The mandate of the Audit, Finance and Risk Committee (the "COMMITTEE") of the Board of Directors (the "BOARD") of Compton Petroleum Corporation (the "COMPANY") is to oversee that management has applied due diligence in creating and maintaining an effective risk management and control framework. This framework should provide reasonable assurance that the financial, operational and regulatory objectives of the Company are achieved and that the statutory responsibilities of the Board are discharged. The Committee fulfils its role on behalf of the Board, by overseeing: 1. the integrity of the Company's financial statements, financial information and accounting, financial reporting (including MD&A, as hereinafter defined) and auditing processes; 2. the external auditor's qualifications, independence and performance; 3. the Company's compliance with legal and regulatory requirements; and 4. risk management, management information systems, governmental legislation and external business of the Company. While the Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the Committee to plan or conduct audits, to determine that the Company's financial statements are complete, accurate and in accordance with generally accepted accounting principles, or to certify the Company's financial statements. Management is responsible for preparing the Company's financial statements and the Company's external auditor is responsible for auditing the annual financial statements and for reviewing the interim financial statements. The Committee shall however assist the Board in overseeing that Management and the external auditor fulfill their responsibilities in the Company's financial reporting process. It is not the duty of the Committee to conduct investigations to assure the Company's compliance with laws, regulations, or the Company's Code of Business Conduct and Ethics. The Committee has the authority to obtain independent legal counsel and outside accounting and other advisors as deemed appropriate to perform its duties and responsibilities. The Company shall provide appropriate funding to compensate the external auditor and any advisors that the Committee chooses to engage. The Committee is authorized to communicate directly with the external auditor to discuss and review specific issues as necessary. The Committee will primarily fulfil its responsibilities by carrying out the activities enumerated in the following sections of this Charter. The Committee will report regularly to the Board regarding the execution of its duties and responsibilities. In fulfilling its mandate, the Committee shall: (A) INTERNAL AND DISCLOSURE CONTROLS -------------------------------- 1. review the effectiveness and integrity of the Company's system of disclosure controls and system of internal controls regarding finance, accounting, compliance and ethics, that Management and the Board have established; 2. where the Committee considers it necessary and appropriate, set up and review an internal audit process and review any appointment or dismissal of senior internal audit personnel appointed in connection therewith; -38- 3. review the evaluation of internal controls by the external auditor with Management and the Company's subsequent follow-up to any identified weaknesses; 4. review, in conjunction with the Corporate Governance Committee of the Board, the appointment of the Chief Financial Officer; 5. determine the appropriate resolution of conflicts of interest in respect of audit, finance and risk matters, properly directed to the Committee; 6. review with Management and the external auditor: (a) in conjunction with the report of the external auditor, the Company's audited annual financial statements, including related footnotes and management's discussion and analysis of financial conditions and results of operations ("MD&A"), and quarterly financial statements, (b) the significant accounting judgments and reporting principles, practices and procedures applied by the Company in preparing its financial statements including any newly adopted accounting policies, (c) significant changes to the audit plan, if any, and any serious disputes or difficulties with management encountered during the audit, (d) the co-operation received by the external auditor during the audit, including access to all requested records, data and information, (e) any correspondence with regulatory or governmental authorities which raises material issues regarding the Company's financial statements or accounting policies, and (f) any other matters not described above that are required to be communicated by the external auditors to the Committee pursuant to applicable law and regulation; 7. obtain an explanation from Management of all significant variances between comparative reporting periods. The Committee shall review all financial statements prior to their presentation to the Board for approval; 8. review and recommend for approval by the Board, all documents to be publicly disclosed, prior to their release, which contain audited or unaudited financial information. Such documents include any prospectuses, interim unaudited financial statements, year end audited financial statements, the annual report, the annual proxy circular, the annual information form, all press releases and disclosures made under MD&A; 9. review with Management the procedures that exist for the review of financial information extracted or derived from financial statements which is publicly disclosed by the Company other than in the documents listed in section 8 above and periodically, at least annually, assess the adequacy of those procedures, as required by Multilateral Instrument 52-110, section 2.3; 10. review with Management and the external auditor all off-balance sheet financing mechanisms being used by the Company, their risks and the clear disclosure of those risks and all other material financial risks to the Company's business; 11. discuss with the Company's General Counsel, at least annually, legal and regulatory matters that may have a material impact on the financial statements; -39- 12. review with the Chief Financial Officer and the Chief Executive Officer of the Company their respective disclosures made to the Committee during the certification process as required by Multilateral Instrument 52-109, including: (a) any significant deficiencies or material weaknesses in the design or operation of internal controls, (b) any fraud involving management or other employees who have a significant role in the Company's internal controls, (c) any other obligations arising from certification, and (d) any significant changes in the internal controls; 13. review with Management and the external auditor the Company's Code of Business Conduct and Ethics, and report to the Corporate Governance Committee in respect thereof; 14. establish and maintain procedures for: (a) the receipt, retention and treatment of complaints received by the Company regarding the Company's accounting, internal accounting controls or auditing matters, and (b) the confidential and anonymous submission by Company employees of concerns regarding questionable accounting or auditing matters, and review all matters relating thereto; and 15. review with Management the details of all transactions between the Company and parties related to the Company; (B) OVERSIGHT OF THE EXTERNAL AUDITOR --------------------------------- 1. recommend to the Board and to the Shareholders the nomination of the external auditor, who shall be a "Registered Public Accounting Firm" within the meaning of applicable securities legislation, for the purpose of preparing or issuing an auditor's report or performing other audit, review or attestation services for the Company; 2. review the qualifications and independence of the external auditor during the year; 3. maintain a clear understanding with the external auditor that it is to have an open and transparent relationship with the Committee and that it is to report directly to the Committee; 4. provide a scheduled opportunity to meet with the external auditor for full, frank and timely discussions of all material issues, without Management present; 5. discuss with the external auditor the scope and timing of the audit work with particular reference to high risk areas or areas of Board concern; 6. inquire as to whether the audit partner receives compensation based on the audit partner procuring engagements to provide services other than audit, review or attest services to the Company; 7. review all reportable events, including disagreements, unresolved issues and consultations, as defined in National Instrument 51-102, on a routine basis, whether or not there is to be a change of external auditor; 8. review all issues and documentation related to a change of external auditor, including information to be included in the Change of Auditor Notice and documentation called for under applicable national instruments, -40- and the planned steps for an orderly transition period; 9. appropriately supervise and evaluate the performance of the external auditor and lead audit partner, and report conclusions to the Board; 10. review and approve the Company's hiring policies regarding partners, employees, former partners and former employees of the current and previous external auditors of the Company; 11. oversee the rotation of audit partners as required by applicable regulation and, in order to ensure continuing auditor independence, consider annually whether it is appropriate to adopt a policy of rotating the Company's external auditing firm on a regular basis; 12. pre-approve the nature of, and fees for, all audit, review, attestation and significant non-audit services provided by the external auditor, prior to engagement, and disclose such pre-approvals in accordance with applicable securities law; 13. consider the effect of significant non-audit engagements on the independence of the external auditor; and 14. provide to the external auditor any information and explanations, and access to records, documents, books, accounts and vouchers of the Company that are, in the opinion of the external auditor, necessary to make the examinations and reports required under legislation or regulation; (C) OVERSIGHT OF FINANCIAL REPORTING AND ACCOUNTING POLICIES -------------------------------------------------------- 1. review with Management and the external auditor significant financial reporting issues arising during the fiscal period and the methods of resolution; 2. prior to the issuance of the external auditor's report on the Company's financial statements, discuss the following with the external auditor: (a) all critical accounting policies and practices applied in the financial statements, (b) all alternative accounting and disclosure treatments of financial information within generally accepted accounting principles that have been discussed with Management, ramifications of the use of such alternate treatments and disclosures, and the treatment preferred by the external auditor, and (c) other material written communications between the external auditor and Management, such as the post audit or management letter and schedule of unadjusted differences; 3. inquire of the external auditor as to the quality of the Company's accounting estimates, discussing significant judgments made in connection with the preparation of the financial statements; 4. review with Management any proposed changes in major accounting policies, the impact and clear disclosure of significant risks and uncertainties and key estimates and judgments of Management that may be material to financial reporting; 5. prepare such reports and letters or other disclosure documents as are required to be prepared by the Committee under applicable securities legislation; and 6. review any notice received by the Committee with respect to an error or misstatement of which a director or officer becomes aware. -41- (D) ADDITIONAL DUTIES AND RESPONSIBILITIES -------------------------------------- 1. review the appointments of the Chief Financial Officer and any other key financial executives who are involved in the financial reporting process; 2. review derivative and hedging policies of the Company and make recommendations to the Board in respect of gas contracts, hedging agreements and other similar financial transactions; 3. review risk assessment and risk management policies. Such review should include the Company's major financial and accounting risk exposures, the steps management has undertaken to control them, and the clear disclosure of such material risks as part of the Company's continuous disclosure requirements; and 4. review the amount and terms of any insurance to be obtained or maintained by the Company, including insurance with respect to potential liabilities incurred by the directors or officers in the discharge of their duties and responsibilities. (E) GENERAL ------- 1. The Committee shall review and assess annually the adequacy of this Charter and recommend any proposed changes to the Board for approval. 2. To fulfill its responsibilities and duties the Committee may: (a) inspect any and all of the books, records and financial affairs of the Company, its subsidiaries and affiliates; and (b) meet with any executive or employee of the Company with or without management to review such accounts, records and other matters as any member of the Committee considers necessary and appropriate. 3. The Committee shall receive reports as required from the Board; Human Resources, Compensation, Environmental, Health and Safety Committee; and the Engineering, Reserves and Operations Committee and discuss with them issues of relevance to the Committee. 4. The Committee shall review when deemed necessary by the Committee any of the financial affairs of the Company, its subsidiaries or affiliates and make recommendations to the Board, to the external auditor, or to management, as appropriate. 5. The Committee shall report regularly to the Board through the Chair of the Committee or through such other person appointed by the Committee the conclusions reached and issues considered by the Committee. 6. The Committee shall perform any other activities consistent with this Charter as the Committee deems necessary or appropriate in order to carry out its mandate. COMPOSITION OF THE COMMITTEE ---------------------------- 1. The Committee shall be comprised of at least three directors. 2. Each member of the Committee shall be "independent", "outside" and "unrelated" (collectively, "independent"), as affirmatively determined by the Board, which, for the purposes of this Charter shall mean: (i) a director who is independent of management and is free from any interest in any business or other relationship which could, or could reasonably be perceived to materially interfere with the director's ability to act with a view to the best interests of the Company, other than interests and relationships arising from shareholdings; -42- (ii) a director who has no direct or indirect material relationship with the Company (a material relationship is a relationship which could, in the view of the Board, reasonably interfere with the exercise of a director's independent judgment), including any relationship explicitly considered to be material under Multilateral Instrument 52-110 of the Canadian Securities Administrators and any other applicable United States or Canadian law or regulation; (iii) other than as a member of the Committee, the Board or any other committee of the Board, a director who does not and has not accepted any consulting, advisory or compensatory fee from the Company; and (iv) a director who is not an "affiliated person" of the Company or any subsidiary thereof within the meaning of applicable United States and Canadian law and regulation. 3. At least half of the members of the Committee must be resident Canadians, as that term is defined in the BUSINESS CORPORATIONS ACT (Alberta). 4. The Board shall appoint the members of the Committee at the first meeting of the Board following each annual meeting ("ANNUAL MEETING") of the shareholders of the Company. 5. The Board shall appoint one member of the Committee to be the Chair of the Committee. 6. A director appointed by the Board to the Committee shall be a member of the Committee until the next Annual Meeting or until his or her earlier resignation or removal by the Board. A member shall cease to be a member of the Committee upon ceasing to be a director of the Company. 7. The Board may remove or replace any member of the Committee at any time. 8. The Company's Corporate Secretary, or in his or her absence, one of the members chosen by the Committee shall be the Secretary of the Committee. 9. Members of the Committee may not serve on the audit committee of more than two additional public companies without the prior approval of the Board. 10. (a) Each member of the Committee shall be financially literate. An individual is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Company's financial statements. (b) A Committee member who is not financially literate may be appointed to the Committee provided that the member becomes financially literate within a reasonable period of time following his or her appointment. (c) At least one member of the Committee shall have accounting or related financial management expertise and, where possible, at least one member of the Committee shall qualify as an "audit committee financial expert" within the meaning of applicable securities legislation. MEETINGS OF THE COMMITTEE ------------------------- 1. The Committee shall convene at such times and places designated by the Chair of the Committee, at least on a quarterly basis, and whenever a meeting is requested by the Board, a member of the Committee, the external auditor, or a senior officer of the Company. The Committee shall meet in separate sessions with management and the external auditor at each regularly scheduled meeting. -43- 2. Notice of each meeting of the Committee shall be given to each member and to the external auditor, who shall be entitled to attend each meeting of the Committee. 3. Notice of a meeting of the Committee shall: (a) be in writing (which may be communicated by electronic facsimile or other communication facilities); (b) state the nature of the business to be transacted at the meeting in reasonable detail; (c) to the extent practicable, be accompanied by copies of documentation to be considered at the meeting; and (d) be given at least 24 hours preceding the time stipulated for the meeting. 4. A quorum for the transaction of business at a meeting of the Committee shall consist of a majority of the members of the Committee. 5. A member of the Committee may participate in a meeting of the Committee by means of such telephonic, electronic or other communication facilities as permit all persons participating in the meeting to communicate adequately with each other. A member participating in such a meeting by any such means is deemed to be present at that meeting. 6. In the absence of the Chair of the Committee, the members of the Committee shall choose one of the members present to be Chair of the meeting and, in the absence of the Secretary of the Committee, the members shall choose one of the persons present to be the Secretary of the meeting. 7. Management of the Company may attend meetings of the Committee as deemed appropriate by the Committee and shall attend meetings of the Committee when requested to do so by the Committee. 8. Minutes shall be kept of all meetings of the Committee and shall be signed by the Chairman and Secretary of the meeting. The minutes shall be maintained with the Company's records, shall include copies of all resolutions passed at each meeting, and shall be available for review by members of the Committee, the Board, management and external auditor. -44-