EX-20 2 ex20-1form40f_2005.txt EXHIBIT 20.1 EXHIBIT 20.1 ------------ [GRAPHIC OMITTED] [LOGO - COMPTON PETROLEUM CORPORATION] ANNUAL INFORMATION FORM FOR THE YEAR ENDED DECEMBER 31, 2005 COMPTON PETROLEUM CORPORATION March 23, 2006 TABLE OF CONTENTS PAGE ABBREVIATIONS AND CONVERSION FACTORS.........................................2 DEFINITIONS..................................................................3 ADVISORIES...................................................................8 CORPORATE STRUCTURE..........................................................8 GENERAL DEVELOPMENT OF THE BUSINESS..........................................9 DESCRIPTION OF THE BUSINESS.................................................10 RISK FACTORS................................................................15 STATEMENT OF RESERVES DATA..................................................19 PRICING ASSUMPTIONS.........................................................23 RECONCILIATION OF CHANGES IN RESERVES AND FUTURE NET REVENUE................24 ADDITIONAL INFORMATION RELATING TO RESERVES DATA............................26 OTHER OIL AND GAS INFORMATION...............................................28 DIVIDENDS...................................................................33 CAPITAL STRUCTURE...........................................................33 MARKET FOR SECURITIES.......................................................34 CONFLICTS OF INTEREST.......................................................34 INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS.................34 MATERIAL CONTRACTS..........................................................35 INTERESTS OF EXPERTS........................................................35 RATINGS ....................................................................35 DIRECTORS AND OFFICERS......................................................36 AUDIT, FINANCE AND RISK COMMITTEE INFORMATION...............................38 COMPOSITION OF AUDIT, FINANCE AND RISK COMMITTEE............................38 EXTERNAL AUDITOR FEES.......................................................38 TRANSFER AGENT AND REGISTRAR................................................39 ADDITIONAL INFORMATION......................................................39 SCHEDULE A..................................................................40 SCHEDULE B..................................................................42 SCHEDULE C..................................................................44 -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; "LT" means long ton; "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; "MLT" means thousands of long tons; "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 ------------------------------------------------------------------------------- cubic feet 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 ------------------------------------------------------------------------------- DEFINITIONS 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. "DEVELOPED NON-PRODUCING" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in and the date of resumption of production is unknown. "DEVELOPED PRODUCING" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production and the date of resumption of production must be known with reasonable certainty. -3- "DEVELOPMENT COSTS" means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves; (b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly; (c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices, production storage tanks, natural gas cycling and processing plants and central utility and waste disposal systems; and (d) provide improved recovery systems. "DEVELOPMENT WELL" means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive. "EUB" means the Alberta Energy and Utilities Board. "EXPLORATION COSTS" means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as "prospecting costs") and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are: (a) costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as "geological and geophysical costs"); (b) costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defense and the maintenance of land and lease records; (c) dry hole contributions and bottom hole contributions; (d) costs of drilling and equipping exploratory wells; and (e) costs of drilling exploratory type stratigraphic test wells. "EXPLORATORY WELL" means a well that is not a development well, a service well or a stratigraphic test well. "FIELD" means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to denote -4- 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 (d) applying to the future, pre-tax cash flows relating to the Company's oil and gas activities and the appropriate year end statutory tax rates, taking into account future tax rates already legislated. "FUTURE NET REVENUE" means the estimated net amount to be received with respect to the development and production of reserves estimated using constant prices and costs or forecast prices and costs. "GROSS" means: (a) in relation to the Company's interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the Company; (b) in relation to wells, the total number of wells in which the Company has an interest; and (c) in relation to properties, the total area of properties in which the Company has an interest. "LIQUIDS" means crude oil, natural gas liquids and sulphur. "NATURAL GAS" or "GAS" means the lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially gases but which may contain natural gas liquids. Natural gas can exist in a reservoir either dissolved in crude oil (solution gas) or in a gaseous phase (associated gas or non-associated gas). Non-hydrocarbon substances may include hydrogen sulphide, carbon dioxide and nitrogen. "NATURAL GAS LIQUIDS" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons. "NET" means: (a) in relation to the Company's interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves; -5- (b) in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and (c) in relation to the Company's interest in a property, the total area of properties in which the Company has an interest multiplied by the working interest owned by the Company. "NON-ASSOCIATED GAS" means an accumulation of natural gas in a reservoir where there is no crude oil. "OPERATING COSTS" or "PRODUCTION COSTS" means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment, facilities and other costs of operating and maintaining those wells and related equipment and facilities. "PROBABLE" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. "PRODUCTION" means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas. "PROPERTY" includes: (a) fee ownership or a lease, concession, agreement, permit, licence or other interest representing the right to extract oil or gas, subject to such terms as may be imposed by the conveyance of that interest; (b) royalty interests, production payments payable in oil or gas and other non-operating interests in properties operated by others; and (c) an agreement with a foreign government or authority under which a reporting issuer participates in the operation of properties or otherwise serves as producer of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer). A property does not include supply agreements or contracts that represent a right to purchase, rather than extract, oil or gas. "PROPERTY ACQUISITION COSTS" means costs incurred to acquire a property directly by purchase or lease, or indirectly by acquiring another corporate entity with an interest in the property, including: (a) costs of lease bonuses and options to purchase or lease a property; (b) the portion of the costs applicable to hydrocarbons when land including rights to hydrocarbons is purchased in fee; and (c) brokers' fees, recording and registration fees, legal costs and other costs incurred in acquiring properties. "PROVED" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Nine out of ten times, proved reserves are likely to increase. "PROVED PROPERTY" means a property or part of a property to which reserves have been specifically attributed. "RESERVES" are estimated remaining quantities of oil, natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on (a) analysis of drilling, geological, geophysical and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally -6- accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates. "RESERVOIR" means a porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. "SERVICE WELL" means a well drilled or completed for the purpose of supporting production in an existing field. Wells in this class are drilled for the following specific purposes: gas injection (natural gas, propane, butane or flue gas), water injection, steam injection, air injection, salt water disposal, water supply for injection, observation or injection for combustion. "SHUT IN WELL" means a well which is capable of economic production or which the Company considers capable of production but which for a variety of reasons, including, but not limited to, lack of markets or development, is not placed on production at the present time. "SOLUTION GAS" means natural gas dissolved in crude oil. "STRATIGRAPHIC TEST WELL" means a geologically directed drilling effort, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (a) "exploratory type" if not drilled into a proved property; or (b) "development type", if drilled into a proved property. Development type stratigraphic wells are also referred to as "evaluation wells". "SUPPORT EQUIPMENT AND FACILITIES" means equipment and facilities used in oil and gas activities, including seismic equipment, drilling equipment, construction and grading equipment, vehicles, repair shops, warehouses, supply points, camps and division, district or field offices. "UNDEVELOPED" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure, when compared to the cost of drilling a well, is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. "UNPROVED PROPERTY" means a property or part of a property to which no reserves have been specifically attributed. "WELL ABANDONMENT COSTS" means costs of abandoning a well (net of salvage value) and of disconnecting the well from the surface gathering system. Costs of abandoning the gathering system or reclaiming the wellsite are not included. -7- ADVISORIES USE OF BOE EQUIVALENTS The oil and natural gas industry commonly expresses production volumes and reserves on a barrel of oil equivalent ("BOE") basis whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil, ngl, and natural gas measurement units into one basis for improved measurement of results and comparisons with other industry participants. In several sections that follow, Compton has used the 6:1 boe measure which is the approximate energy equivalency of the two commodities at the burner tip. However, boes do not represent a value equivalency at the plant gate where Compton sells its production volumes and therefore may be a misleading measure if used in isolation. FORWARD LOOKING STATEMENTS Certain information regarding the Company contained herein constitutes forward looking statements under the meaning of applicable securities laws, including the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance, or other statements that are not statements of fact, including statements regarding (i) cash flow, 2006 production estimates, reserve estimates, capital expenditures, 2006 drilling program, tax estimates, total future net revenue, pricing assumptions, abandonment and reclamation costs, and (ii) other risks and uncertainties described from time to time in the reports and filings made by Compton with securities regulatory authorities. Although Compton believes that the expectations reflected in such forward looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. There are many factors that could cause forward looking statements not to be correct, including risks and uncertainties inherent in the Company business. These risks include, but are not limited to: crude oil and natural gas price volatility, exchange rate fluctuations, availability of services and supplies, operating hazards and mechanical failures, uncertainties in the estimates of reserves and in projection of future rates of production and timing of development expenditures, general economic conditions, and the actions or inactions of third-party operators, and other risks set forth in the "Risk Factors" section of this Annual Information Form. Compton may, as considered necessary in the circumstances, update or revise forward looking information, whether as a result of new information, future events, or otherwise. The Company's forward looking statements are expressly qualified in their entirety by this cautionary statement. CORPORATE STRUCTURE NAME AND INCORPORATION Compton was incorporated by articles of incorporation pursuant to the provisions of the Business Corporations Act (Alberta) on October 15, 1992, as 544201 Alberta Ltd. The articles were amended on April 13, 1993, to change the Company's name to Compton Petroleum Corporation and the Company commenced active business operations in July 1993. The articles were amended on November 21, 1994 and March 1, 1996, in order to remove the private company restrictions contained in the articles. A further amendment was made to the articles on September 1, 1998, in order to create a class of preferred shares issuable in series. The Company's head and principal office is located at Suite 3300, 425 - 1st Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada, T2P 3L8. Compton's registered office is located at Suite 3000, 237 - 4th Avenue, S.W., Fifth Avenue Place, West Tower, Calgary, Alberta, Canada, T2P 4X7. Effective January 31, 2001, a general partnership called Compton Petroleum was formed under the laws of Alberta. Compton Petroleum Corporation and Hornet Energy Ltd, a wholly-owned subsidiary of Compton Petroleum Finance Corporation, are the partners of the partnership. The majority of our production activities are carried out through this partnership. Compton Petroleum Finance Corporation, formed under the laws of Alberta, is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Petroleum Finance Corporation has no independent operations and has no significant liabilities or assets other than US$300 million of 7 5/8% Senior Notes, its equity interest in Hornet Energy -8- Ltd. and intercorporate indebtedness. The registered office of Compton Petroleum Finance Corporation is 4300 Bankers Hall West, 888 - 3rd Street S.W., Calgary, Alberta, Canada, T2P 5C5. Compton Petroleum Holdings Corporation, formed under the laws of Alberta, is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Petroleum Holdings Corporation has no independent operations and has no significant liabilities or assets other than owning US$158,250,000 aggregate principal amount of 9.90% Notes and intercorporate indebtedness. The registered office of Compton Petroleum Holdings Corporation is 4300 Bankers Hall West, 888 - 3rd Street S.W., Calgary, Alberta, Canada, T2P 5C5. [GRAPHIC OMITTED -- ORGANIZATIONAL CHART] ----------------------------- 100% ---------- Compton Petroleum Corporation ----------- 96% | ----------------------------- | | | | | 100% | | | | -------------------- ------------------------- ----------------- Compton Petroleum Compton Petroleum Finance Compton Petroleum Holdings Corporation Corporation (partnership) -------------------- ------------------------- ----------------- | | 100% 4% | | ------------------ | Hornet Energy Ltd. ---------------- ------------------ The consolidated financial statements include the accounts of the Company and all of its subsidiaries and partnerships. GENERAL DEVELOPMENT OF THE BUSINESS Compton is an Alberta based independent public company actively engaged in the exploration, development, and production of natural gas, ngls, and crude oil in the Western Canada Sedimentary Basin (the "WCSB") in Canada. Compton commenced operations in 1993 with $1 million of share capital, a small dedicated technical team, and a large seismic database. The objective was to build a company through internal, full cycle exploration, complemented by strategic acquisitions. Compton's goal was to create a company capable of long term sustained growth with a primary focus on natural gas. Compton's focus and strategy have remained unchanged since conception. Compton's shares are listed on the Toronto Stock Exchange under the symbol CMT and on the New York Stock Exchange under the symbol CMZ. THREE YEAR HISTORY In 2003, Compton focused on the resolution of pipeline and facility constraints in its Southern Alberta core area. The Mazeppa Processing Partnership, which is not affiliated with Compton, 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 was then able to continue to 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. Compton's capital program totaled $285 million, including the consolidation of the Mazeppa gas plant expenditures. The Company drilled 168 gross (134 net) wells in 2003 with an 83% success rate. In 2004, the expansion of the Mazeppa gas plant from 90 MMcf/d to 135 MMcf/d through the addition of 45 MMcf/d of sweet gas processing capacity was completed. This expanded Compton's processing capacity in Southern Alberta to 200 MMcf/d and removed all restrictions. The Mazeppa Processing Partnership completed the $75 million external financing of the acquisition, expansion, and operations of the Mazeppa facilities and repaid funds borrowed from Compton. -9- Consolidated capital expenditures totaled $316 million in 2004 and Compton drilled 186 gross (146 net) wells with a 90% success rate. Of the wells drilled, 77% were classified as development wells and 23% were classified as exploratory wells. Approximately 26 MMBoe was added to the Company's proved plus probable reserves through drilling successes, acquisitions, and extensions. Total proved plus probable reserves increased 22% from the prior year to 145 MMBoe. In 2005, progress was made on each of the Company's five resource plays including the Edmonton Horseshoe Canyon coalbed methane, plains Belly River, Basal Quartz at Hooker and thrusted, foothills Belly River at Callum in Southern Alberta, and the Rock Creek/Gething play at Niton in Central Alberta. Compton was one of the top 10 most active operators in Canada throughout the year. The Company's consolidated capital program of $513 million, included drilling 392 gross (334 net) wells with a 96% success rate. The drilling program resulted in an exit production rate of 35,500 boe/d and average production of 29,424 boe/d for the year. High commodity prices and increased production generated record revenue of $558 million. Compton's proved plus probable reserves totaled 207 MMBoe as at December 31, 2005. Approximately 62 MMBoe was added to the Company's proved plus probable reserves through drilling successes, acquisitions, and extensions. DESCRIPTION OF THE BUSINESS EXPLORATION AND PRODUCTION OPERATIONS Compton's exploration, development and exploitation activities are concentrated principally in three core areas: 1) Southern Alberta targeting the plains Belly River, Edmonton Horseshoe Canyon coalbed methane ("CBM"), Hooker Basal Quartz and thrusted, foothills Belly River at Callum; 2) Central Alberta targeting the Gething/Rock Creek at Niton; and 3) the Peace River Arch area producing from the Charlie Lake pool at Cecil/Worsley. These areas are the geographic focus of Compton's seismic database and are areas in which Compton's Management ("MANAGEMENT") and staff have significant technical expertise and operational experience. BUSINESS PLAN AND OPERATING STRATEGY The Company's business plan is to grow Compton's reserves and maximize production and cash flow from its core geographic areas and other areas where Compton has technical expertise. Management is implementing this objective by focusing on the efficient exploration, development and exploitation of ithe Company's properties, controlling operating costs, adding economic reserves and production, and making strategic acquisitions in its core areas. Compton has experienced professional, management, technical, and support staff sufficient to carry out its business plan and its current exploration, exploitation, development, production, engineering, financial, and administrative functions. The Company's operating strategy includes the components set forth below: CONCENTRATE ON CORE AREAS. Compton is focused on its core areas, which provide a balanced portfolio of exploration, development, and exploitation prospects. These areas are the geographic focus of the Company's seismic database rights, and are areas in which Management and staff have significant technical expertise and operational experience. Compton intends to generate exploration opportunities and to increase the Company's undeveloped land base within the WCSB. FOCUS ON UNCONVENTIONAL NATURAL GAS IN LARGE RESOURCE PLAYS. As of December 31, 2005, 73% of proved reserves were natural gas. The Company has gained considerable technical expertise and achieved significant success in exploring for unconventional, larger natural gas accumulations in the WCSB. Compton plans to continue to focus on finding and developing these types of natural gas opportunities because of their generally lower decline curves and higher economic return over the life of the reserves compared to conventional natural gas opportunities. The large scale nature of the Company's resource plays also offers multiple low-risk drilling locations resulting in lower costs and decreased exploration risk. -10- PURSUE GROWTH THROUGH THE DRILL BIT COMPLEMENTED BY SELECTIVE ACQUISITIONS. Compton plans to continue to reinvest internally generated cash flow and to use other sources of capital to fund the growth of the Company's exploration and development programs and to further increase its undeveloped land base to maintain a growing inventory of drilling prospects in core areas. In 2004, Compton began an accelerated drilling program. Based on plans for an annual drilling program of 500 to 700 gross wells, the Company has over ten years of drilling inventory on existing lands. Most of these planned wells are expected to be in close proximity to producing wells in existing core areas. Compton's drilling success rate has been at or above 90% for each of the past three years, providing confidence in the Company's ability to successfully grow reserves and production from its extensive inventory of drilling locations. CONTROL INFRASTRUCTURE AND OPERATORSHIP. Compton believes that control over gathering and processing infrastructure and operatorship of drilling programs will continue to be critical to the success of the Company's full-cycle exploration program. Compton currently owns or has access to critical infrastructure in each of its three core areas. Being an operator ensures discretion in determining the timing and methodology of ongoing exploration, development, and exploitation programs. Compton expects to continue to expand its working interest in core areas to maximize these operating efficiencies. MAINTAIN FINANCIAL FLEXIBILITY. The Company is committed to maintaining financial flexibility sufficient to allow it to pursue its full-cycle exploration program in periods of low commodity prices and to respond to opportunities for strategic acquisitions as they arise. Compton has historically funded its exploration, development, and exploitation capital program through internally generated cash flow and has financed acquisitions through bank debt, the issuance of common shares, or a combination thereof. The Company's accelerated drilling program has recently been, and will continue to be, funded through internally generated cash flow, the issuance of additional equity and debt, and non-core property sales. Other components of Compton's financial discipline include establishing appropriate leverage ratios and maintaining an active commodity hedging program. PRINCIPAL PROPERTIES SOUTHERN ALBERTA Southern Alberta remains the primary focus of Compton's activities. The Company holds 804,007 (699,751 net) acres of land in the South, which are prospective for multiple zones including Basal Quartz at Hooker, thrusted Belly River at Callum, Wabamun/Crossfield, Plains Belly River, and Edmonton/CBM. In 2005, Compton drilled 195 (183 net) wells in Southern Alberta with a 99% success rate. The Company anticipates spending $361 million and drilling 277 wells in the area in 2006. HOOKER BASAL QUARTZ During the past year, Compton continued the development of its Lower Cretaceous Basal Quartz resource play at Hooker. The play covers an extensive area of 260,270 (195,200 net) acres. In 2005, the Company drilled 27 wells, extending the productive limits and optimizing reserve recovery in the heart of the pool. In 2005, Compton designed and completed several advanced core and log analysis studies to gain a better understanding of the petrophysical characteristics of the play. As a result of this work, the Company now estimates that the Hooker pool contains at least 1.5 TCF of gas-in-place. Compton is currently conducting further engineering and geological studies to confirm its expectations that the gas-in-place may be greater than initially determined. It has also become evident that the edges of the Hooker pool are not yet clearly identified and as such, Compton has designed its 2006 drilling program to infill and extend the productive limits of the pool. The Hooker play is currently drilled on one to two wells per section, however, engineering models and geological studies indicate that at least three wells per section will be required to maximize reserve recovery from this low permeability gas pool. Compton has made an application to the EUB to conduct a pilot drilling program on two sections in the pool to evaluate the effectiveness of reduced spacing. -11- PLAINS BELLY RIVER AND HORSESHOE CANYON COALBED METHANE In 2005, the Company drilled 170 Belly River wells in the Centron, Gladys, and Brant areas, with all wells encountering multiple pay sections and uphole producible Edmonton/Horseshoe Canyon Coals. The Belly River drilling program continues to exceed expectations. Compton further refined its Belly River seismic and geological models during the year. The use of the Company's extensive 3D and 2D seismic database was critical to identifying the best producible sands. The models were tested and confirmed through drilling. Compton currently has approval to drill two wells per section on seven townships of land. The Alberta Energy and Utilities Board recently announced a phased modification to spacing for the Belly River in Southern Alberta that is intended to see the standard spacing change from one well per section to four wells per section. This initiative would effectively double the number of Belly River drilling locations in the Company's inventory. In anticipation of reduced spacing approval, Compton initiated three 3D seismic programs to assist in the identification of downspace locations. Drilling in select areas on reduced spacing is expected to start during the third quarter of 2006. This will allow Compton to dramatically ramp up its Belly River/Edmonton drilling program, commencing in 2007. Compton will also define the optimum development of the vertical section of Belly River and Edmonton Horseshoe Canyon zones. The Company plans to drill 250 wells in 2006 that will have the potential to be completed in both zones. In addition, Compton has drilled over 400 wells through the Edmonton Horseshoe Canyon formation into the Belly River sands and the Company is planning to re-complete 70 of these wells in the Edmonton in 2006. Compton holds 664,175 (597,760 net) acres of land in Southern Alberta that is prospective for dry Edmonton Horseshoe Canyon coalbed methane and the underlying Plains Belly River sands. During 2005, Compton drilled and cored four CBM pilots across its Southern Alberta acreage to gather the necessary geological evidence to better quantify its CBM resource potential. Each pilot consisted of four to six wells, for a total of 19 wells drilled. In-line flow testing on the initial pilots commenced in the first quarter of 2006 and two additional pilots are in various stages of well licensing. The pilots assessed the potential of 483,560 (435,200 net) acres of the Company's lands in the South. Compton worked closely with Netherland, Sewell & Associates, Inc., ("Netherland Sewell") independent reserve evaluators, throughout the pilot programs to quantify the resource potential associated with the Horseshoe Canyon coals. Netherland Sewell has determined the original unrisked gas-in-place in the Horseshoe Canyon coals to be 3.05 Tcf and Compton estimates the net original unrisked gas-in-place on the Company's acreage to be 2.7 Tcf. This gas-in-place number is restricted to the coals only, with no interbedded Edmonton sands, silts, or shales included. Additionally, the pilot evaluations excluded any potential gas that may be present in the overlying Scollard Formation. As confirmed by well logs, the remaining 177,780 (160,000 net) acres of Compton's acreage contain Edmonton sands, silts, and Horseshoe Canyon coals, and will require further core confirmation of the gas content. In 2006, Compton will evaluate and quantify the potential of the Edmonton sands and silts across the Company's acreage in 2006. The Company has production from the Edmonton Horseshoe Canyon coals at Centron, Gladys, Brant, and Ghost Pine. Currently Belly River production extends across Compton's Southern Alberta lands. CALLUM THRUSTED BELLY RIVER The Callum property consists of a series of low permeability, overpressured, thrusted Upper Cretaceous Belly River sands in the foothills of Southern Alberta. Subsequent to year end, the Company acquired its partner's working interest in the play and now holds a 100% interest in 70,400 acres of land. -12- In the second quarter of 2005, the Company drilled a 100% working interest natural gas well at Callum. Specialized core analysis techniques were used to assist in identifying more prospective intervals and to optimize completion fluids and frac design parameters. The lowermost sand in the stacked Belly River sequence was completed in this well and Compton plans to monitor and analyze this single zone performance before completing prospective uphole zones. The well was placed on continuous production in December 2005. The first two weeks of initial production averaged approximately 1,525 boe per day from a single sand and the well is continuing to produce approximately 300 boe per day as at the end of February 2006. This well has significantly improved the Company's geological, geophysical, and engineering models of the play. The resultant advances in the understanding of this complex reservoir are a major step forward in the development of the Callum play. The play is technically complex and the key to successfully developing the Callum prospect rests with rock characterization and completion optimization. In the eight Compton wells drilled to date, various completion techniques have been evaluated. All wells have produced gas and initial production ranged from 300 Mcfe/d to 8 MMcfe/d. A second well was drilled in December 2005, encountering multiple sands. The well has since been cased and Compton is currently testing. The second well will be completed using methods pioneered by Compton on its previous well. In 2006, 10 wells are planned at Callum. Based on Compton's initial detailed geological, geophysical, and engineering analysis of seismic, cores, well logs, test and production data, Callum appears to exhibit many similarities to the deep unconventional gas pools of the Rocky Mountain region of the United States, specifically in the Greater Green River Basin in Wyoming. CENTRAL ALBERTA Central Alberta provides Compton with excellent exploration and development drilling opportunities using analogous techniques gained through its years of experience in Southern Alberta unconventional gas development. Compton has an average 55% working interest in 541,643 (297,475 net) acres of land. In 2005, the Company drilled 73 (38 net) wells with a 97% success rate and plans to drill 90 wells in the area in 2006. NITON The Niton area, where the majority of Compton's Central Alberta acreage lies, is characterized by multi-zone, deep basin targets analogous to the Hooker pool in Southern Alberta. The Company has an interest in 137,390 (103,040 net) acres of land in the play targeting the Gething and Rock Creek formations. In 2005, 33 wells were drilled and results have continued to exceed expectations. As a result of the Company's successful drilling program at Niton, the Compton owned McLeod River gas plant will be operating at maximum capacity of 20 MMcf/d in the first half of 2006. The Company is currently evaluating plant expansion alternatives, as well as the option of routing a portion of its production to adjacent non-operated plants, in which the Company holds minor working interests. PEACE RIVER ARCH The Peace River Arch area, located north of Grande Prairie, contains multi-zone 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 averages a 61% working interest in 199,040 (121,634 net) acres of land in the area. In 2005, Compton drilled 124 (114 net) wells in the Arch with an 89% success rate and plans to drill 106 wells in 2006. CECIL/WORSLEY Compton's 2005 drilling program at Worsley was extremely successful, significantly increasing the reserve value and production from the area. The Company drilled 80 Charlie Lake oil wells, more than twice the original number budgeted, which resulted in pool boundary extensions in all directions. -13- Approval for a pool wide waterflood on the Charlie Lake H and J pool at Worsley was received in February 2005 and a total of eight wells have been converted to injectors thus far. The waterflood is projected to increase the ultimate recovery factor for the pool to 25% from 15% on primary depletion. The Company will continue its program at Worsley in 2006 and anticipates drilling 90 wells in the upcoming year. At Cecil, 23 100% working interest and 9 non-operated 40% working interest horizontal Charlie Lake oil wells were drilled in 2005. All wells encountered excellent pay zones and have been systematically brought on production throughout 2005 and into the first quarter of 2006. Compton is undertaking geological and engineering work to evaluate additional waterflood potential in the Cecil area. The Company plans to drill 17 wells in 2006 and to focus on optimizing production from its previously drilled horizontal wells. PRINCIPAL MARKETS AND DISTRIBUTION METHODS Compton's natural gas production is sold under a combination of longer term contracts with aggregators and short term daily or 30 day AECO indexed contracts. Approximately 10% of the Company's natural gas production in 2005 was committed to aggregators, compared to an average of 11% in 2004. The average aggregator price realized in 2005 was $1.25/Mcf less than the non-aggregator prices realized during the year. Natural gas production is transported through regulated pipelines within Alberta, at tolls requiring government approval. The Company's crude oil sales are priced at Edmonton postings and are typically sold on 30 day evergreen arrangements. Natural gas liquids are bid out on an annual basis to obtain the most favorable pricing. The Company sells crude oil and natural gas liquids primarily to refineries and marketers of crude oil and natural gas liquids. Liquids may be transported through regulated pipelines or trucked to the point of sale. ENVIRONMENTAL POLICIES Compton believes in the importance of protecting the environment. The Company is committed to conducting all operations in a safe manner that minimizes environmental impact, while meeting regulatory requirements and corporate standards. The Company maintains a comprehensive range of internal programs and controls to promote regulatory compliance and an appropriate level of safety and environmental protection across its operations. The Company's proactive program includes annual environmental compliance audit and inspection programs to ensure Compton's facilities continually meet or exceed regulatory standards. The Company has participated in programs for continual improvement set forth by the Canadian Association of Petroleum Producers, Alberta Energy and Utilities Board, Alberta Environmental Protection, and other related associations, thus demonstrating Compton's commitment to minimizing the Company's environmental impact. The Company carries out its activities in compliance with all relevant regulations and industry best practices. At present, the Company believes that it meets all existing environmental standards and regulations and has included appropriate amounts in its capital expenditure budget to continue to meet current environmental protection requirements. The Company does not anticipate making extraordinary material expenditures for environmental compliance during 2006. However, it does expect to incur site restoration costs over a prolonged period as existing wells become fully produced. Compton provides for future abandonment and reclamation costs in its financial statements in accordance with Canadian generally accepted accounting principles. MAZEPPA PROCESSING PARTNERSHIP In June of 2003, Mazeppa Processing Partnership ("MPP") acquired certain midstream assets from an independent third party. The assets consist of major natural gas gathering and processing facilities in Southern Alberta. Compton does not have an ownership position in MPP. Through a management agreement, Compton manages the activities of MPP and is therefore considered to be the primary beneficiary of MPP's operations. As a result, Compton consolidates the accounts of MPP for reporting purposes in accordance with the guidelines issued by the Accounting Standards Board, in Accounting Guideline AcG-15, "Consolidation of Variable Interest Entities." The results of the midstream activities are immaterial to Compton's consolidated financial condition. -14- EMPLOYEES As at December 31, 2005, Compton had 155 full-time employees in its Calgary office and 43 full-time employees at field locations. COMPETITIVE CONDITIONS Producers benefited from high oil and gas prices in 2005, increasing revenue and cash flow. However, higher commodity prices also accelerated capital programs throughout the industry, resulting in service and supply shortages and increasing the overall cost of doing business. As commodity prices weakened in the first few months of 2006 due to unseasonably warm weather and concern over the high natural gas storage levels, field and operating netbacks decreased. Land prices continue to climb, adding considerably to finding, development, and acquisition ("FD&A") costs, as well as consuming a larger portion of annual budgets. In Compton's core areas, prices at recent land sales are up to four times what the Company originally paid for its undeveloped acreage. Drilling rigs, service rigs, equipment, and experienced crews continue to operate at or near maximum capacity, which results in escalating drilling costs and inefficiencies. Deeper drilling and more complex plays have contributed to higher FD&A costs for the industry in general. Strong demand for experienced professionals has caused a significant increase in salaries and workloads, further adding to inefficiency in the industry. Additionally, the increasing complexity and ever changing government rules regarding license applications, environmental regulations, and governance matters is adding significantly to overall cost and time required to complete operations. The mergers and acquisitions ("M&A") market in 2005 was quite strong and it appears the high level of activity will continue in 2006. The M&A market is being driven by several factors. High commodity prices and the belief they will stay high are raising the value of oil and gas producers in the equity market, while large amounts of available cash in combination with rising FD&A are encouraging producers to seek growth through acquisitions. RISK FACTORS VOLATILITY OF PRICES, MARKETS AND MARKETING PRODUCTION Oil and gas prices have historically been extremely volatile. The average prices that the Company currently receives for its production are significantly higher than historic averages. Factors which contribute to oil and gas price fluctuations include global demand, domestic and foreign supplies of oil and gas, the price of foreign oil and gas imports, decisions of the Organization of Petroleum Exporting Countries relating to export quotas, domestic and foreign governmental regulations, political conditions in producing regions, global and domestic economic conditions, the price and availability of alternative fuels, including liquefied natural gas, and weather conditions. The Company's financial condition is substantially dependent on, and highly sensitive to, oil and gas commodity prices. Any material decline in prices could result in a material reduction of Compton's operating results, revenue, reserves, and overall value. Lower commodity prices could change the economics of production from some wells. As a result, the Company could elect not to drill, develop, or produce from certain wells. In addition, Compton is impacted by the differential between prices paid by refiners for light quality oil and the grades of oil produced by the Company. Under Canadian GAAP, oil and gas assets are reviewed quarterly to determine if the carrying value of the assets exceeds their expected future cash flows. A sustained period of low commodity prices may reduce expected future cash flows and require a write down to the fair value of the Company's oil and gas properties, thereby adversely affecting operating results. Any future and sustained period of weakness in oil and gas prices would also have an adverse effect on the Compton's capacity to borrow funds. The Company's senior secured credit facilities, as the borrowing amount determined by the lenders, is based on their estimate of the value of the Company's proved reserves. A reduction in the quantity or value of reserves may also obligate Compton to make additional payments under the processing agreement with MPP. -15- Any decline in the Company's ability to market production could have a material adverse effect on production levels or on the sale price received for production. Compton's ability to market the oil and gas from the Company's wells depends on numerous factors beyond the Company's control, including the availability and capacity of gas gathering systems, pipelines and processing facilities, and their proximity to the wells. The Company will be impacted by Canadian federal and provincial, as well as U.S. federal and state, energy policies, taxes, regulation of oil and gas production, processing, and transportation, as well as Canadian federal regulation of oil and gas sold or transported outside of the province of Alberta. NEED TO REPLACE RESERVES Compton's future success depends upon the Company's ability to find, develop, or acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development, exploitation, or acquisition activities, the Company's reserves will deplete and, as a consequence, either production or the average life of reserves will decline. If future production declines to the extent that cash flow becomes insufficient to fund capital expenditures, and external sources of capital become limited or unavailable, the Company's ability to make the necessary capital expenditures to maintain and expand its oil and gas reserves will be impaired. Compton cannot guarantee that the Company will be able to find and develop or acquire additional reserves at an acceptable cost. Management will continue to evaluate prospects on an ongoing basis in a manner consistent with industry standards and past practices. The long term commercial success of the Company depends on its ability to find, acquire, develop, and commercially produce oil and gas reserves. No assurance can be given that Compton will be able to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, the Company may determine that current markets, terms of acquisition and participation, or pricing conditions make such acquisitions or participations uneconomic. Compton's strategies to minimize this inherent risk include focusing on selected core areas in Western Canada with high working interests and assuming operatorship of key facilities. The Company utilizes a team of highly qualified professionals with expertise and experience in these areas. Compton assesses strategic acquisitions to complement existing activities while striving for a balance between exploration and lower risk development and exploitation prospects. UNCERTAINTY OF RESERVE ESTIMATES Estimates of oil and gas reserves and the future net cash flow therefrom, involve a great deal of uncertainty because they depend upon the reliability of available geologic and engineering data, which is inherently imprecise. Geologic and engineering data are used to determine the probability that an oil and gas reservoir exists at a particular location, and whether oil and gas are recoverable from the reservoir. The probability of the existence and recoverability of reserves is less than 100% and actual recoveries of proved reserves may be materially different from estimates. Estimates of oil and gas reserves require numerous assumptions relating to operating conditions and economic factors, including future oil and gas prices, recovery costs, the availability of enhanced recovery techniques, the ability to market production, and governmental and other regulatory factors, such as taxes, royalty rates, and environmental laws. A change in one or more of these factors could result in known quantities of oil and gas previously estimated as proved reserves becoming unrecoverable. Each of these factors also impact recovery costs and production rates, and therefore, will reduce the present value of future net cash flows from estimated reserves. In addition, estimates of reserves and future net cash flows expected therefrom, that are prepared by different independent engineers or by the same engineers at different times, may vary substantially. EXPLORATION, DEVELOPMENT AND PRODUCTION RISKS There are many operating risks and hazards inherent in exploring for, producing, processing, and transporting oil and gas. Drilling operations may encounter unexpected formations or pressures that could cause damage to equipment or personal injury and fires, explosions, blowouts, oil spills, or other accidents may occur. Additionally, -16- Compton could experience interruptions to or the termination of drilling, production, processing, and transportation activities due to bad weather, natural disasters, delays in obtaining governmental approvals or consents, insufficient storage or transportation capacity, or other geological and mechanical conditions. Any of these events resulting in a shutdown or slowdown of operations, will adversely affect the Company's business. While close well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. Drilling activities, including completions, are subject to the risk that no commercially productive reservoirs will be encountered and the Company will not recover all or any portion of its investment. The cost of drilling, completing, and operating wells is often uncertain due to drilling in unknown formations, the costs associated with encountering various drilling conditions such as over pressured zones, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. INSURANCE The risks and hazards of Compton's operations could result in damage to, or destruction of, oil and gas wells, production and processing facilities, pipelines or other property, environmental damage, or personal injury for which the Company will be liable. The location of operations near populated areas, including residential areas, commercial business centers, and industrial sites could increase these risks and hazards. The Company cannot fully protect against all of these risks, nor are all of these risks insurable. Compton may become liable for damages arising from these events against which it cannot insure or against which it may elect not to insure because of high premium costs or other reasons. The occurrence of a significant event not fully insured or indemnified against could seriously harm Compton's financial condition and operating results. COMPETITION The oil and gas industry is highly competitive. The Company competes for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, and pipeline and refining capacity with a substantial number of other organizations, many of which may have greater technical and financial resources than Compton. Some of these organizations not only explore for, develop and produce oil and gas but also carry on refining operations and market crude oil and other products on a worldwide basis. As a result of these complementary activities, some competitors may have greater and more diverse competitive resources to draw on than Compton does. AVAILABILITY OF DRILLING EQUIPMENT AND ACCESS RESTRICTIONS Compton's drilling operations could be curtailed, delayed, or cancelled as a result of access restrictions or shortages or delays in the delivery of equipment and services. Oil and gas industry operations in the WCSB are affected by road bans imposed from time to time, which can restrict access to well sites and production facility sites. In addition, landowner constraints or poor surface conditions could disrupt access to the Company's properties. Compton's inability to access the Company's properties or to conduct business as planned could result in a shutdown or slowdown of operations. Exploration and development activities also depend on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Increased demand for that equipment or imposed access restrictions may affect the availability of equipment to the Company and may delay exploration and development activities. ADDITIONAL FUNDING REQUIREMENTS Compton's ongoing activities may not generate sufficient cash flow from operations to fund future exploration, development, or acquisition programs. The Company may require additional funding and there can be no assurance that debt or equity financing will be available or sufficient to meet these requirements or that it will be on acceptable terms. Failure to obtain such financing on a timely basis could cause Compton to forfeit interests in certain properties, miss certain acquisition opportunities, and reduce or terminate operations. This may result in the -17- Company not being able to replaces its reserves or maintain production, which will have an adverse effect on its financial position. RELIANCE ON KEY EMPLOYEES Compton depends to a large extent on the services of key management personnel, including the Company's executive officers and other key employees, the loss of any of whom could have a material adverse effect on operations. The Company does not maintain key man life insurance with respect to any employees. Compton's success will be dependent upon its ability to continue to employ and retain skilled personnel. ENVIRONMENTAL RISKS The oil and gas industry is subject to extensive environmental laws and regulations pursuant to local, provincial, and federal legislation. Environmental regulation provides for, among other things, restrictions and prohibitions on the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste from spills, releases or emissions of various substances produced in association with oil and gas operations. The legislation also requires that wells, facility sites, and other properties associated with the Company's operations be operated, maintained, abandoned, and reclaimed to the satisfaction of applicable regulatory authorities. Under environmental legislation, Compton may be liable for personal injury, clean-up costs, remedial measures, and other environmental and property damages, as well as administrative, civil, and criminal penalties. Furthermore, future changes in environmental laws and regulations, including adoption of stricter standards or more stringent enforcement, could result in curtailment of production or materially increased costs, such as fines, incurred liability and increased capital expenditures and operating costs, any of which could have a material adverse effect on financial condition. For example, Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide, and other so-called "greenhouse gases." Compton's production facilities and other operations and activities emit greenhouse gases that may subject the Company to legislation regulating emissions of greenhouse gases. The Government of Canada has proposed a Climate Change Plan for Canada that suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas development and production. Future federal legislation, together with provincial emission reduction requirements, such as those proposed in Alberta's Bill 32: Climate Change and Emissions Management, may require the reduction of emissions or emissions intensity of the Company's operations and facilities. Compliance with such legislation can require significant expenditures and a failure to comply may result in the issuance of "clean up" orders or the imposition of fines and penalties, some of which may be material. It is possible that the costs of complying with environmental regulations in the future will have a material adverse effect on the Company's financial condition or results of operations. Compton may incur liabilities that could be material or require the Company to cease production on properties if environmental damage occurs. Compton has not established a separate reclamation fund for the purpose of funding estimated future environmental and reclamation obligations. The Company cannot assure that it will be able to satisfy future environmental and reclamation obligations. Any site reclamation or abandonment costs incurred in the ordinary course in a specific period will be funded out of cash flow from operations. Should Compton be unable to fully fund the cost of remedying an environmental claim, the Company might be required to suspend operations or enter into interim compliance measures pending completion of the required remedy. The Company is not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, Compton's properties may be subject to liability due to hazards that cannot be insured against or that have not been insured against due to prohibitive premium costs or for other reasons. -18- STATEMENT OF RESERVES DATA Compton's interests in its natural gas and crude oil properties as of December 31, 2005, have been evaluated in a report (the "REPORT") as of December 31, 2005, 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 net revenue are after the deduction of future income tax expenses (unless otherwise noted in the tables), royalties, development costs, production costs, and well abandonment costs, but before consideration of indirect costs such as administrative, overhead, and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of Compton's reserves. There is no assurance that the forecast price and cost assumptions contained in the Netherland Sewell Report will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables. The recovery and reserves estimates on Compton's properties described herein are estimates only. The actual reserves on Compton's properties may be greater or less than those calculated and these variances may be material. Compton has no heavy oil reserves and "crude oil" refers to light and medium crude oil only. This statement is dated February 24, 2006. The information being provided in this statement has an effective date of December 31, 2005 and a preparation date of February 24, 2006. CONSTANT PRICES AND COSTS The following table provides a summary of the Company's reserves by product type, based upon constant price and cost assumptions, before and after applicable royalties, 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, 2005 ----------------------------------------------------------------------------------------------------------- RESERVES CATEGORY (1) CRUDE OIL NATURAL GAS (2) NGLS SULPHUR GROSS NET GROSS NET GROSS NET GROSS NET (MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MLT) (MLT) ----------------------------------------------------------------------------------------------------------- PROVED Developed producing 14,222 13,206 430,136 349,723 7,937 5,635 1,605 1,428 Developed non-producing 3,195 2,951 44,496 35,519 830 566 52 41 Undeveloped 5,029 4,313 84,539 70,260 1,731 1,278 118 98 ----------------------------------------------------------------------------------------------------------- TOTAL PROVED 22,445 20,470 559,171 455,503 10,498 7,479 1,774 1,566 -----------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding. (2) The solution and associated gas represents 6% of the Company's natural gas reserves and is 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, 2005 based on constant price and cost assumptions. -19-
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2005 (CONSTANT PRICES) ----------------------------------------------------------------------------------------------- RESERVES CATEGORY NET PRESENT VALUES OF FUTURE NET REVENUE ($000S)(1) BEFORE INCOME TAXES AFTER INCOME TAXES DISCOUNTED AT (%/YEAR) DISCOUNTED AT (%/YEAR) 0% 10% 0% 10% ----------------------------------------------------------------------------------------------- PROVED Developed producing $3,376,094 $1,609,730 $2,403,561 $1,183,126 Developed non-producing 471,650 240,652 337,390 175,280 Undeveloped 795,420 301,318 557,529 213,100 ----------------------------------------------------------------------------------------------- TOTAL PROVED $4,643,164 $2,151,700 $3,298,480 $1,571,506 -----------------------------------------------------------------------------------------------
(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, 2005 (CONSTANT PRICES) ----------------------------------------------------------------------------------------------------------------------- RESERVES REVENUE ROYALTIES OPERATING DEVELOPMENT WELL FUTURE NET INCOME TAXES FUTURE NET CATEGORY ($000S) ($000S) COSTS COSTS ABANDONMENT REVENUE BEFORE ($000S) REVENUE AFTER ($000S) ($000S) COSTS ($000S) INCOME TAXES INCOME TAXES ($000S) ($000S) ----------------------------------------------------------------------------------------------------------------------- Proved $8,086,809 $1,514,951 $1,718,793 $187,687 $22,214 $4,643,164 $1,344,684 $3,298,480 -----------------------------------------------------------------------------------------------------------------------
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, 2005 (CONSTANT PRICES) ---------------------------------------------------------------------------------------------------------- RESERVES CATEGORY PRODUCTION TYPE FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED AT 10%/YEAR) ($000S) ---------------------------------------------------------------------------------------------------------- Proved Crude Oil (1) $ 611,314 Natural Gas, ngls, and sulphur (2) $1,540,386 ----------------------------------------------------------------------------------------------------------
(1) Includes solution gas and related ngls. (2) Excludes solution gas and related ngls. -20- FORECAST PRICES AND COSTS A summary of the Company's reserves by product type based upon forecast price and cost assumptions, before and after applicable royalties, 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, 2005 --------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY (1) CRUDE OIL NATURAL GAS NGLS SULPHUR GROSS NET GROSS NET GROSS NET GROSS NET (MBBL) (MBBL) (MMCF) (MMCF) (MBBL) (MBBL) (MLT) (MLT) --------------------------------------------------------------------------------------------------------------- PROVED Developed producing 13,537 12,533 423,961 344,320 7,837 5,591 1,603 1,426 Developed non-producing 3,131 2,888 44,332 35,385 828 568 52 41 Undeveloped 5,019 4,304 84,333 70,085 1,731 1,283 118 98 --------------------------------------------------------------------------------------------------------------- TOTAL PROVED 21,688 19,725 552,626 449,790 10,396 7,441 1,773 1,565 PROBABLE 6,805 5,762 401,415 337,719 6,232 4,629 772 656 --------------------------------------------------------------------------------------------------------------- TOTAL PROVED PLUS PROBABLE 28,493 25,488 954,040 787,509 16,628 12,070 2,545 2,221 ---------------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding. The tables set forth below summarize the net present value of future net revenue as of December 31, 2005 based on forecast prices and cost assumptions.
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2005 (FORECAST PRICES) ---------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY (1) NET PRESENT VALUES OF FUTURE NET REVENUE ($000S) BEFORE INCOME TAXES DISCOUNTED AT (%/YEAR) 0% 5% 8% 10% 15% 20% ---------------------------------------------------------------------------------------------------------------- PROVED Developed producing $2,809,295 $1,790,246 $1,502,423 $1,367,244 $1,136,835 $989,296 Developed non-producing 407,231 275,162 231,040 209,205 170,528 145,066 Undeveloped 673,954 369,776 278,044 234,937 162,989 119,410 ---------------------------------------------------------------------------------------------------------------- TOTAL PROVED 3,890,479 2,435,184 2,011,507 1,811,386 1,470,353 1,253,772 PROBABLE 2,308,449 1,155,102 830,029 681,260 439,847 299,340 ---------------------------------------------------------------------------------------------------------------- TOTAL PROVED PLUS PROBABLE $6,198,928 $3,590,286 $2,841,537 $2,492,645 $1,910,200 $1,553,112 ----------------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding. -21-
----------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY (1) NET PRESENT VALUES OF FUTURE NET REVENUE ($000S) AFTER INCOME TAXES DISCOUNTED AT (%/YEAR) 0% 5% 8% 10% 15% 20% ----------------------------------------------------------------------------------------------------------------- PROVED Developed producing $2,023,759 $1,341,801 $1,126,747 $1,024,244 $ 849,212 $ 738,331 Developed non-producing 295,311 201,924 170,478 154,939 127,372 109,188 Undeveloped 478,428 267,812 201,919 170,878 119,110 87,859 ----------------------------------------------------------------------------------------------------------------- TOTAL PROVED 2,797,499 1,811,537 1,499,144 1,350,061 1,095,694 935,377 PROBABLE 1,537,575 767,481 534,430 427,302 254,907 156,833 ----------------------------------------------------------------------------------------------------------------- TOTAL PROVED PLUS PROBABLE $4,335,073 $2,579,018 $2,033,574 $1,777,363 $1,350,601 $1,092,210 -----------------------------------------------------------------------------------------------------------------
(1) Numbers may not add due to rounding. Undiscounted total future net revenue calculated using forecast prices and costs incorporates the elements presented in the table below.
TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF DECEMBER 31, 2005 -------------------------------------------------------------------------------------------------------------------- RESERVES REVENUE ROYALTIES OPERATING DEVELOPMENT WELL FUTURE NET INCOME FUTURE NET CATEGORY ($000S) ($000S) COSTS COSTS ABANDONMENT REVENUE BEFORE TAXES REVENUE AFTER ($000S) ($000S) COSTS(1) INCOME TAXES ($000S) INCOME TAXES ($000S) ($000S) ($000S) -------------------------------------------------------------------------------------------------------------------- Proved $ 7,823,503 $1,436,847 $2,265,900 $192,916 $37,361 $3,890,479 $1,092,980 $2,797,499 Proved plus probable $12,577,769 $2,253,840 $3,251,277 $811,508 $62,216 $6,198,928 $1,863,855 $4,335,073 --------------------------------------------------------------------------------------------------------------------
(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, 2005 -------------------------------------------------------------------------------------------------------------------- RESERVES CATEGORY PRODUCTION TYPE FUTURE NET REVENUE BEFORE INCOME TAXES (DISCOUNTED AT 10%/YEAR) ($000S) -------------------------------------------------------------------------------------------------------------------- Proved Crude Oil (1) $ 542,624 Natural Gas and ngls (2) $1,268,762 Proved plus probable Crude Oil (1) $ 645,369 Natural Gas and ngls (2) $1,847,276 --------------------------------------------------------------------------------------------------------------------
(1) Includes solution gas and related ngls. (2) Excludes solution gas and related ngls. -22- PRICING ASSUMPTIONS CONSTANT PRICES USED IN ESTIMATES Constant price assumptions presume the continuance of current laws, regulations, and operating costs in effect on the date of the Report. Future net revenue calculated using constant prices and costs is based upon the price assumptions set out below. The prices are founded upon the assumptions made by Netherland Sewell as of December 31, 2005.
SUMMARY OF CONSTANT PRICING ASSUMPTIONS AS OF DECEMBER 31, 2005 --------------------------------------------------------------------------------------------------------------------- YEAR CRUDE OIL NATURAL GAS NGLS SULPHUR EXCHANGE RATE WTI CUSHING EDMONTON PAR AECO-C SPOT PROPANE BUTANE PENTANES+ PLANT GATE $CDN/$US OKLAHOMA 40 DEGREES API ($CDN/MMBTU) ($CDN/BBL) ($CDN/BBL) ($CDN/BBL) ($CDN/LT) $ US/BBL ($CDN/BBL) --------------------------------------------------------------------------------------------------------------------- Dec. 31, 2005 $61.04 $67.85 $9.99 $51.59 $63.52 $71.03 $13.17 0.858 ---------------------------------------------------------------------------------------------------------------------
FORECAST PRICES USED IN ESTIMATES Future net revenue calculated using forecast prices and costs is based upon the price assumptions set out below. Netherland Sewell incorporated price forecast which were the average of the December 31, 2005 pricing forecasts prepared by four major Canadian consulting firms in estimating Compton's reserves data using forecast pricing and costs.
SUMMARY OF FORECAST PRICING AND INFLATION RATE ASSUMPTIONS AS OF DECEMBER 31, 2005 (1) ----------------------------------------------------------------------------------------------------------------------- YEAR CRUDE OIL NATURAL GAS NGLS SULPHUR INFLATION EXCHANGE RATE (2) RATE WTI CUSHING EDMONTON PAR AECO-C SPOT PROPANE BUTANE PENTANES+ PLANT GATE %/YEAR $CDN/$US OKLAHOMA 40 DEGREES API ($CDN/MMBTU) ($CDN/BBL)($CDN/BBL) ($CDN/BBL) ($CDN/LT) $US/BBL ($CDN/BBL) --------------------------------------------------------------------------------------------------------------------------- FORECAST 2006 $58.83 $68.13 $10.93 $43.28 $50.13 $69.99 $33.67 2.0% 0.85 2007 $58.30 $67.55 $ 9.91 $42.48 $49.67 $69.55 $23.77 2.0% 0.85 2008 $55.14 $63.80 $ 8.47 $39.95 $47.08 $65.80 $16.70 2.0% 0.85 2009 $52.32 $60.49 $ 7.72 $37.59 $44.74 $62.39 $15.14 2.0% 0.85 2010 $50.18 $57.96 $ 7.50 $35.93 $42.89 $59.83 $15.68 2.0% 0.85 2011 $49.18 $56.78 $ 7.56 $35.18 $41.94 $58.59 $16.38 2.0% 0.85 2012 $49.96 $57.66 $ 7.68 $35.75 $42.59 $59.49 $16.92 2.0% 0.85 2013 $50.97 $58.80 $ 7.84 $36.40 $43.44 $60.68 $17.47 2.0% 0.85 2014 $51.96 $59.98 $ 8.01 $37.15 $44.30 $61.88 $18.18 2.0% 0.85 2015 $53.01 $61.22 $ 8.21 $37.93 $45.19 $63.17 $18.91 2.0% 0.85 2016 $54.07 $62.42 $ 8.38 $38.70 $46.08 $64.46 $19.47 2.0% 0.85 Thereafter 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 0.85 ---------------------------------------------------------------------------------------------------------------------------
(1) Pricing assumptions are the average of four major Canadian oil and gas evaluation firms. (2) Inflation rates for forecasting operating costs and capital investments. The weighted average realized sales price for Compton for the year ended December 31, 2005 was $8.42/MCF for natural gas, $62.02/BBL for crude oil, $47.34/BBL for ngls, and $12.63/LT for sulphur. -23- RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE RESERVES RECONCILIATION The following table provides a summary of the changes in the Company's reserves which occurred in the most recent fiscal year, based upon forecast price and cost assumptions, net of applicable royalties.
RECONCILIATION OF NET RESERVES BY RESERVE TYPE USING FORECAST PRICES AND COSTS (NET OF APPLICABLE ROYALTIES) (1) ----------------------------------------------------------------------------------------------------------------- CRUDE OIL NGLS NET NET NET PROVED NET NET NET PROVED PROVED PROBABLE PLUS PROBABLE PROVED PROBABLE PLUS PROBABLE (MBBL) (MBBL) (MBBL) (MBBL) (MBBL) (MBBL) ----------------------------------------------------------------------------------------------------------------- December 31, 2004 11,018 6,669 17,687 6,256 3,520 9,776 Extensions 1,532 359 1,891 431 1,921 2,352 Improved recovery 3,626 1,671 5,297 190 379 569 Technical revisions 4,057 (3,148) 909 614 (1,246) (632) Discoveries 409 42 451 260 45 305 Acquisitions 514 169 683 208 10 218 Dispositions - - - (2) - (2) Production (1,431) - (1,431) (516) - (516) ----------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2005 19,725 5,762 25,488 7,441 4,629 12,070 ----------------------------------------------------------------------------------------------------------------- ----------------------------------------------------------------------------------------------------------------- NATURAL GAS SULPHUR NET NET NET PROVED NET NET NET PROVED PROVED PROBABLE PLUS PROBABLE PROVED PROBABLE PLUS PROBABLE (MBCF) (MBCF) (MBCF) (MLT) (MLT) (MLT) ----------------------------------------------------------------------------------------------------------------- December 31, 2004 359,029 168,808 527,837 1,445 791 2,236 Extensions 33,694 118,596 152,290 9 353 362 Improved recovery 10,555 83,259 93,814 - - - Technical revisions 61,544 (45,976) 15,568 191 (488) (297) Discoveries 16,310 12,362 28,672 - - - Acquisitions 5,564 670 6,234 - - - Dispositions (56) - (56) - - - Production (36,850) - (36,850) (80) - (80) ----------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2005 449,790 337,719 787,509 1,565 656 2,221 -----------------------------------------------------------------------------------------------------------------
(1) Prepared by Management. Numbers may not add due to rounding. -24-
RECONCILIATION OF NET RESERVES BY RESERVE TYPE USING FORECAST PRICES AND COSTS (1) ----------------------------------------------------------------------------------------------------------------- TOTAL RESERVES NET NET NET PROVED PROVED PROBABLE PLUS PROBABLE (MBOE) (MBOE) (MBOE) ----------------------------------------------------------------------------------------------------------------- December 31, 2004 78,557 39,115 117,672 Extensions 7,588 22,399 29,987 Improved recovery 5,575 15,927 21,502 Technical revisions 15,119 (12,545) 2,575 Discoveries 3,387 2,147 5,535 Acquisitions 1,649 291 1,940 Dispositions (11) - (11) Production (8,169) - (8,169) ----------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2005 103,696 67,334 171,031 -----------------------------------------------------------------------------------------------------------------
(1) Prepared by Management. Numbers may not add due to rounding. FUTURE NET REVENUE RECONCILIATION The following table reconciles changes between the future net revenue estimates at December 31, 2005 and the corresponding estimates in the prior year, using constant prices and costs, discounted at 10%.
RECONCILIATION OF CHANGES IN NET PRESENT VALUE DISCOUNTED AT 10% OF FUTURE NET REVENUE OF PROVED RESERVES (1) ----------------------------------------------------------------------------------------------------------------- 2005 ($000S) (2) ----------------------------------------------------------------------------------------------------------------- Estimated future net revenue at beginning of year $1,000,772 Sales and transfers of oil and gas produced, net of production costs and royalties 336,711 Net change in sales, prices, production costs and royalties related to future production 614,690 Changes in previously estimated development costs incurred during the period (306,199) Changes in estimated future development costs (135,499) Net change from extensions and improved recovery 265,868 Net change from discoveries 88,318 Acquisitions of reserves (7,749) Dispositions of reserves 87 Net change resulting from revisions in quantity estimates 526,474 Accretion of discount 100,077 Net change in income taxes(3) (331,850) ----------------------------------------------------------------------------------------------------------------- Estimated future net revenue at end of year $2,151,700 -----------------------------------------------------------------------------------------------------------------
(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. -25- 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. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. It requires significant judgments and decisions based on available geological, geophysical, engineering, and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and natural gas prices and costs change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. The reserve estimates contained herein are based on current production forecasts, prices, and economic conditions. Compton's reserves are evaluated by Netherland Sewell. -26- 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 2006 $106,989 $107,976 $254,694 2007 45,136 46,541 222,114 2008 24,156 25,511 167,141 2009 2,362 2,805 70,830 2010 4,659 5,229 35,800 Remaining 26,599 42,215 123,2144 ---------------------------------------------------------------------------------------------------------- Total undiscounted $209,901 $230,277 $873,724 Total discounted at 10% per year $171,801 $178,181 $683,029 ----------------------------------------------------------------------------------------------------------
(1) Includes abandonment costs. Numbers may not add due to rounding. Compton estimates that its internally generated cash flow will be sufficient to fund the future development costs disclosed above. Compton typically has available three sources of funding to finance its capital expenditure program: (i) internally generated cash flow from operations; (ii) debt financing when appropriate; and (iii) new equity issues, if available on favourable terms. -27- OTHER OIL AND GAS INFORMATION OIL AND GAS PROPERTIES AND WELLS The following table summarizes the location of the Company's interests as at December 31, 2005, in crude oil and natural gas wells which are producing or which the Company considers to be capable of production.
------------------------------------------------------------------------------------------------------------- AREA PRODUCING CRUDE SHUT-IN CRUDE PRODUCING SHUT-IN NATURAL TOTAL WELLS OIL WELLS OIL WELLS NATURAL GAS GAS WELLS WELLS GROSS NET GROSS NET GROSS NET GROSS NET GROSS NET ------------------------------------------------------------------------------------------------------------- ALBERTA South 108 48 32 12 820 525 216 176 1,176 761 Central 162 78 31 9 360 150 122 45 675 282 Peace River Arch 334 207 26 11 122 - 24 14 506 233 BC 6 - 2 - 42 2 12 1 62 3 ------------------------------------------------------------------------------------------------------------- TOTAL WELLS 610 333 91 32 1,344 677 374 236 2,419 1,279 -------------------------------------------------------------------------------------------------------------
The number of shut in oil and gas wells capable of production at December 31, 2005 increased from 2004 because well tie-ins were delayed as the result of abnormally wet weather during the summer months of 2005. 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, 2005.
------------------------------------------------------------------------------------------------------------- AREA GROSS ACRES NET ACRES ------------------------------------------------------------------------------------------------------------- British Columbia 34,019 5,390 Alberta 907,482 704,148 Saskatchewan 23,157 23,157 Manitoba 6,659 6,259 ------------------------------------------------------------------------------------------------------------- TOTAL 971,317 738,954 -------------------------------------------------------------------------------------------------------------
Approximately 211,270 net acres of undeveloped land could expire by December 31, 2006. However, the Company's 2006 exploration and development activities may defer the expiry of a portion of these lands. Compton has $65 million of work commitments associated with unproved properties. FORWARD CONTRACTS In 2005, Compton's realized average field price was $51.95/BOE, comprised of $8.42/MCF for natural gas and $56.04/BBL for liquids. In 2004, the average field prices of natural gas and liquids were $6.46/MCF and $43.21/BBL, respectively, for an average price of $39.82/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 10% of the Company's natural gas production in 2005 was committed to aggregators. The average aggregator price realized was $1.25/MCF less than the non-aggregator prices realized during the year. -28- 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. 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 1,449 net well sites and facilities is the sum of the calculated abandonment and reclamation liabilities adjusted for designated status as active, inactive, abandoned, or problem site. Information regarding environmental remediation costs and other liability issues for site specific concerns were derived from a review of historical audit and assessment reports of sites and facilities. An inflation rate of 2% and a credit adjusted risk free rate of 10.7% was used in the fair value calculation. Total asset retirement costs, net of estimated salvage values, is $77 million or $6 million when discounted at 10%. The undiscounted ARO associated with pipelines and facilities is $49 million and is not deducted in estimating total future net revenue, as calculated in the Company's reserve report. The Company expects to pay $2 million dollars in ARO costs between 2006 and 2009. TAX HORIZON Based upon planned capital expenditure programs and current commodity price assumptions, it is anticipated the Company will not be cash taxable until at least 2009. CAPITAL EXPENDITURES In 2005, Compton incurred $72 million of exploration costs and $424 million of development costs. Additionally, $29 million was spent on proved property acquisitions and $12 million was spent on unproved property acquisitions. -29- EXPLORATION AND DEVELOPMENT ACTIVITIES The following table sets forth the number of crude oil and natural gas wells drilled by the Company, or which the Company participated in drilling, that are capable of production, as well as the number of dry and abandoned wells, all expressed in terms of gross and net wells during the years ended December 31, 2005 and 2004. Four wells drilled in 2005, which are standing cased wells awaiting completion and testing, are not included in the following table.
------------------------------------------------------------------------------------------------------------------- YEAR ENDED DECEMBER 31, 2005 YEAR ENDED DECEMBER 31, 2004(1) DEVELOPMENT EXPLORATORY DEVELOPMENT EXPLORATORY GROSS NET GROSS NET GROSS NET GROSS NET ------------------------------------------------------------------------------------------------------------------- Natural Gas 197 156 60 56 108 89 31 26 Crude Oil 104 96 10 9 29 17 - - Dry and Abandoned 9 8 8 7 7 3 11 10 ------------------------------------------------------------------------------------------------------------------- TOTAL 310 260 78 72 144 110 42 36 SUCCESS RATIO 96% 90% ------------------------------------------------------------------------------------------------------------------- (1) 2004 revised to include four wells previously classified as standing cased wells.
In 2006, the Company will continue to focus its resources in Alberta, Canada. Compton's overall objective for 2006 is the recognition of its unbooked resource potential. The Company has developed an aggressive $575 million capital expenditure plan for 2006, encompassing up to 480 gross wells. -30- PRODUCTION HISTORY The Company's average daily production volume of natural gas and liquids, before deduction of royalties, for each of the periods indicated, is set forth below.
GROSS NATURAL GAS AND LIQUIDS PRODUCTION ------------------------------------------------------------------------------------------------------------------ PRODUCT TYPE FISCAL 2005 THREE MONTHS ENDED YEAR ENDED MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31, 2005 2005 2005 2005 2005 ------------------------------------------------------------------------------------------------------------------ Natural gas (MMCF/D) 130 130 130 133 131 Natural gas (MMCF) 11,677 11,809 11,973 12,234 47,693 Liquids (BOE/D) 7,090 7,249 7,351 8,879 7,646 Liquids (MBBLS) 638 660 676 817 2,791 ------------------------------------------------------------------------------------------------------------------ ------------------------------------------------------------------------------------------------------------------ PRODUCT TYPE FISCAL 2004 THREE MONTHS ENDED YEAR ENDED MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31, 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 (BOE/D) 5,655 5,977 6,712 6,963 6,330 Liquids (MBBLS) 515 544 618 640 2,317 ------------------------------------------------------------------------------------------------------------------
2006 PRODUCTION ESTIMATES Production volumes in 2006 as estimated in the reserve forecast before deduction of royalties are set forth below. Production volumes are the same in both the constant price case and the forecast price case.
------------------------------------------------------------------------------------------------------------ RESERVES CATEGORY (1) CRUDE OIL NATURAL GAS NGLS SULPHUR TOTAL (BBL/D) (MMCF/D) (BBL/D) (LT/D) (BOE/D) ------------------------------------------------------------------------------------------------------------ PROVED Developed producing 4,944 99 1,726 178 23,267 Developed non-producing 1,394 14 230 3 3,934 Undeveloped 994 7 184 - 2,406 ------------------------------------------------------------------------------------------------------------ TOTAL PROVED 7,332 120 2,140 181 29,606 PROBABLE 384 23 302 13 4,614 ------------------------------------------------------------------------------------------------------------ TOTAL PROVED PLUS PROBABLE 7,716 143 2,442 194 34,221 ------------------------------------------------------------------------------------------------------------ (1) Numbers may not add due to rounding. Based on estimates only. Variances may occur due to circumstances beyond Compton's control.
-31- The Company's field netbacks for natural gas and liquids for each of the periods indicated is set forth below.
NATURAL GAS AND LIQUIDS FIELD NETBACKS ------------------------------------------------------------------------------------------------------------------- FISCAL 2005 THREE MONTHS ENDED YEAR ENDED MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31, 2005 2005 2005 2005 2005 ------------------------------------------------------------------------------------------------------------------- NATURAL GAS ($/MCF) Revenue price $6.60 $7.28 $8.46 $11.20 $8.42 Royalties, net (1.66) (1.76) (2.23) (2.54) (2.06) Operating costs (1.03) (1.01) (1.00) (1.10) (1.04) Transportation costs (0.13) (0.17) (0.19) (0.18) (1.07) ------------------------------------------------------------------------------------------------------------------- Field netback $3.78 $4.34 $5.05 $ 7.38 $5.15 LIQUIDS ($/BBL) Revenue price $46.23 $54.20 $64.75 $57.99 $56.04 Royalties, net (9.99) (10.53) (13.37) (15.24) (12.36) Operating costs (6.15) (6.09) (5.98) (6.63) (6.22) Transportation costs (0.80) (1.01) (1.13) (1.09) (1.01) ------------------------------------------------------------------------------------------------------------------- Field netback $29.29 $36.56 $44.28 $35.03 $36.45 ------------------------------------------------------------------------------------------------------------------- ------------------------------------------------------------------------------------------------------------------- FISCAL 2004 THREE MONTHS ENDED YEAR ENDED MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, DECEMBER 31, 2004 2004 2004 2004 2004 ------------------------------------------------------------------------------------------------------------------- NATURAL GAS ($/MCF) Revenue price $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 $3.79 LIQUIDS ($/BBL) Revenue price $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 -------------------------------------------------------------------------------------------------------------------
-32- 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 127,294,201 common shares are issued and outstanding as fully paid and non-assessable share as at March 23, 2006. No preferred shares are issued and outstanding as at March 23, 2006. The following is a description of Company's common and preferred shares. COMMON SHARES Common shares have attached to them the following rights, privileges, restrictions, and conditions: (i) except for meetings at which only holders of another specified class or series of shares of the Company are entitled to vote separately as a class or series, each holder of a common share is entitled to receive notice of, to attend and to vote at all meetings of the shareholders of the Company; (ii) subject to the rights, privileges, restrictions, and conditions attached to any preferred shares, the holders of common shares are entitled to receive dividends if, and when declared by the Directors of the Company; and (iii) subject to the rights, privileges, restrictions, and conditions attached to any other class of shares of the Company, the holders of common shares are entitled to share equally in the remaining property of the Company upon liquidation, dissolution, or winding-up of the Company. PREFERRED SHARES The preferred shares may be issued in one or more series, and the Directors are authorized to fix the number of shares in each series and to determine the designation, rights, privileges, restrictions, and conditions attached to the shares of each series. The preferred shares are entitled to a priority over the common shares with respect to the payment of dividends and the distribution of assets upon the liquidation, dissolution, or winding-up of Compton. SHAREHOLDER RIGHTS PLAN Compton has a shareholder rights plan (the "RIGHTS PLAN") under the terms of a shareholder rights plan agreement dated as of April 22, 2003 between the Company and Computershare Trust Company of Canada, as rights agent. The Rights Plan is designed to encourage the fair treatment of shareholders in connection with a take-over bid for Compton. Rights issued under the Rights Plan become exercisable when a person, and any related parties, acquires or announces its intention to acquire 20% or more of the outstanding Common Shares without complying with certain provisions set out in the Rights Plan or without approval of the Board of Directors of Compton. Should such an acquisition or announcement occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase Common Shares at a 50% discount to the market price at that time. -33- MARKET FOR SECURITIES The outstanding common shares of the Company are listed on the Toronto Stock Exchange ("TSX") under the symbol CMT and on the New York Stock Exchange until the symbol CMZ. The following table sets out the high and low closing prices and average trading volume of common shares as reported by the TSX, for the periods indicated.
------------------------------------------------------------------------------------------ PERIOD TSX HIGH CLOSE TSX LOW CLOSE TSX AVERAGE DAILY TRADING VOLUME ------------------------------------------------------------------------------------------ 2005 January $11.65 $10.51 516,574 February $12.65 $11.46 667,961 March $13.74 $11.30 634,532 April $12.45 $10.26 549,281 May $10.82 $ 9.95 1,065,189 June $11.65 $10.70 842,449 July $13.70 $11.32 809,324 August $14.21 $13.10 835,428 September $15.90 $13.90 700,544 October $16.00 $12.90 562,113 November $15.40 $12.65 691,408 December $18.40 $16.69 951,082 2006 January $18.84 $17.01 743,850 February $18.92 $14.39 773,430 March 1-23 $15.87 $13.95 668,241 ------------------------------------------------------------------------------------------
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, directly or indirectly, in any transaction or proposed transaction that has materially affected or would materially affect Compton. -34- MATERIAL CONTRACTS Indenture dated as of November 22, 2005, among Compton Petroleum Finance Corporation, Compton, as parent guarantor, Hornet Energy Ltd., Compton Petroleum (partnership) and Compton Petroleum Holdings Corporation, as the initial subsidiary guarantors, and The Bank of Nova Scotia Trust Company of New York, as trustee, whereby, on November 22, 2005, Compton Petroleum Finance Corporation issued and sold U.S.$300 million aggregate principal amount of senior term notes, which are unsecured and bear interest semi-annually, in arrears on December 1, and June 1 of each year, at a rate of 7 5/8% per year with principal repayable on December 1, 2013. The senior notes are guaranteed by Compton and the initial subsidiary guarantors. INTERESTS OF EXPERTS As at the date hereof, the partners and associates of Grant Thornton, LLP, the auditors of Compton, as a group, did not beneficially own any of Compton's outstanding 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 ("S&P") and Moody's Corporation ("MOODY'S") have rated Compton's U.S. 300 million 7 5/8% Senior Notes as B stable and B2 stable respectively, as at December 31, 2005. A security rating is not a recommendation to buy, sell, or hold securities and may be subject to revisions or withdrawal at any time by the rating agency. An S&P credit rating considers likelihood of payment, nature of and provisions of the obligation, protection afforded by, and relative position of, the obligation in the event of bankruptcy, reorganization, or other arrangement under the laws of bankruptcy and other laws affecting creditors' rights. S&P's credit ratings are on a long-term debt rating scale that ranges from AAA to D, representing the range from highest to lowest quality of such securities rated. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories. According to the S&P rating system, debt securities rated B are vulnerable to nonpayment, but the obligor currently has the capacity to meet its financial commitment on the obligation. Adverse business, financial, or economic conditions will likely impair the obligor's capacity or willingness to meet its financial commitment on the obligation. Moody's credit ratings on long-term structured finance obligations primarily address the expected credit loss an investor might incur on or before the legal final maturity of such obligations, incorporating the probability of default and the severity of the loss. Moody's credit ratings are on a long-term debt rating scale that ranges from Aaa to C, representing the range from least credit risk to greatest credit risk of such securities rated. Moody's applies numerical modifiers 1, 2 and 3 in each generic rating classification from Aa through Caa in its long term debt rating system. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking, and the modifier 3 indicates that the issue ranks in the lower end of that generic rating category. According to the Moody's rating system, debt securities rated B2 are considered speculative and are subject to high credit risk. -35- DIRECTORS AND OFFICERS DIRECTORS Information is given below with respect to each of the current Directors of the Company. All Directors of Compton stand for election at each annual meeting of the Company. The next Annual Meeting of Shareholders is scheduled for May 10, 2006 at 3:30 pm. (Calgary time) in the Historical Ballroom on the 4th Floor of the Calgary Chamber of Commerce, 517 - Centre Street South, Calgary, Alberta, Canada. The Board of Directors has established an Audit, Finance and Risk Committee; an Engineering, Operations and Reserves Committee; a Human Resources, Compensation, Environmental, Health and Safety Committee; and a Corporate Governance Committee. All independent Directors sit on each of the Board Committees. Mr. Sapieha does not sit on the Board Committees since he is a non-independent Director due to his position as President & CEO with the Company. The name, city of residence, and principal occupation during the last five years of each of the Directors of the Company are set forth in the following table.
--------------------------------------------------------------------------------------------------------------------- NAME AND MUNICIPALITY OF PRINCIPAL OCCUPATION DIRECTOR SINCE RESIDENCE --------------------------------------------------------------------------------------------------------------------- Mel F. Belich, Q.C. Group Vice President, Corporate Law, of Enbridge Inc., an energy 1993 Calgary, AB, Canada transportation and distribution company. Mr. Belich has also been Chairman and President of each of Enbridge International Inc., Enbridge Technology Inc., and a director of numerous Enbridge affiliates, including those in Europe and Latin America. Mr. Belich is the Chairman of the Board of Directors of Compton and the Chairman of the Corporate Governance Committee. --------------------------------------------------------------------------------------------------------------------- Irvine J. Koop, P. Eng. Chairman and Chief Executive Officer, IKO Resources Inc., a petroleum 1996 Calgary, AB, Canada consulting firm and prior thereto, President and CEO, Pipelines and 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, AB, Canada company. --------------------------------------------------------------------------------------------------------------------- Ernie G. Sapieha, C.A. President & Chief Executive Officer of the Company. 1993 Calgary, AB, Canada --------------------------------------------------------------------------------------------------------------------- Jeffrey T. Smith, P. Geol. Independent Businessman and prior thereto, Chief Operating Officer of 1999 Calgary, AB, Canada Northstar Energy Corporation. Mr. Smith is Chairman of the Engineering, Reserves and Operations Committee. ---------------------------------------------------------------------------------------------------------------------
-36-
--------------------------------------------------------------------------------------------------------------------- NAME AND MUNICIPALITY OF PRINCIPAL OCCUPATION DIRECTOR SINCE RESIDENCE --------------------------------------------------------------------------------------------------------------------- John A. Thomson, C.A. Independent Businessman. Mr. Thomson served as Vice President 2003 Calgary, AB, Canada Corporate Development from 2000 and as a director from 1999 to 2001, of Avid Oil & Gas Ltd., an oil and gas company and prior thereto, he was Senior Vice President and Chief Financial Officer of Renaissance Energy Ltd., an oil and gas Company. Mr. Thomson is the Chairman of the Audit, Finance and Risk Committee. ---------------------------------------------------------------------------------------------------------------------
Further information about the Directors and the committees of the Board of Directors is set forth under the heading "Election of Directors" in the Company's Management Proxy Circular dated March 15, 2006 relating to the Annual Meeting of Shareholders to be held on May 10, 2006, 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 Marc R. Junghans, P. Geol. Vice President Exploration; prior to 2002, Manager of Exploration of the Calgary, Alberta Company. ----------------------------------------------------------------------------------------------------------------
As at March 23, 2006, the Directors and officers of Compton as a group beneficially owned or controlled, directly or indirectly, 12,920,564 common shares of Compton, representing approximately 10.2% of the issued and outstanding common shares of the Company. None of the Directors or Officers held a sufficient number of common shares to materially affect the control of Compton. -37- 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 Based upon applicable Canadian and United States securities laws and the New York Stock Exchange corporate governance rules, Compton has adopted "Standards of Independence," which may be viewed in full on the Company's website. The Board affirmatively determines on an annual basis the independence of its members. Messrs. Belich, Koop, Preston, Smith, and Thomson have been determined to be independent Directors. Mr. Sapieha is not an independent Director because of his position as President & CEO of the Company. Mr. Thomson is considered to be a "financial expert", as defined in National Instrument 52-110, 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, due to their experience in various management positions. EXTERNAL AUDITOR FEES The aggregate amounts paid or accrued by the Company with respect to fees payable to Grant Thornton LLP for audit and audit-related (including separate audits of subsidiary entities, financings, and regulatory reporting requirements), tax and other services in the fiscal years ended December 31, 2005 and 2004 were as follows: -------------------------------------------------------------------------------- TYPE OF SERVICE FISCAL 2005 FISCAL 2004 (1) -------------------------------------------------------------------------------- Audit $481,230 $350,455 Audit related 221,997 131,315 Tax 10,000 9,000 Other non-audit 41,930 49,598 -------------------------------------------------------------------------------- Total $755,157 $540,368 -------------------------------------------------------------------------------- (1) 2004 amounts have been updated to account for differences between accrued costs and actual billings. The audit related fees incurred in fiscal 2005 related to the Company's equity offering in February 2005 and the issuance of the Company's U.S. dollar Senior Notes in November 2005. Tax fees incurred in fiscal 2005 related to the review of tax forms and the fees for other non-audit services in fiscal 2005 were incurred to translate the Company's quarterly and annual reports into French. The audit related fees incurred in fiscal 2004 related to discussions regarding the accounting treatment for the Mazeppa Processing Partnership. 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 of 2002. 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. -38- TRANSFER AGENT AND REGISTRAR The transfer agent and registrar for the Company's shares is Computershare Trust Company of Canada at its office in Calgary, Alberta. ADDITIONAL INFORMATION Additional information including Directors' and Officers' remuneration, principal holders of the Company's common shares, options to acquire common shares, and interests of insiders in material transactions (if applicable) is contained in the Management Proxy Circular issued by Management dated March 15, 2006, relating to the Annual and Special Meeting of Shareholders to be held on May 10, 2006. Additional financial information is also provided in the consolidated financial statements and MD&A of the Company for the year ended December 31, 2005 included in the Company's 2005 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 Corporation Suite 3300, 425 - 1st Street S.W. Fifth Avenue Place, East Tower Calgary, Alberta, Canada T2P 3L8 Attention: Mr. T.G. Millar Vice President, General Counsel & Corporate Secretary Telephone: (403) 237-9400 Fax: (403) 237-9410 -39- 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, 2005. The reserves data consist of the following: (a) (i) proved and proved plus probable oil and gas reserves estimated as at December 31, 2005 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, 2005 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, 2005 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 & February 24, 2006 Canada nil 2,492,645.40 nil 2,492,645.40 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. -40- 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, 2006 By: /s/ Frederic D. Sewell ------------------------------------ Frederic D. Sewell Chairman and Chief Executive Officer Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document. -41- 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, 2005 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, 2005 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. -42- Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material. (signed) "Ernie Sapieha" (signed) "Murray Stodalka" Ernie Sapieha Murray Stodalka President & CEO Vice President Operations & Engineering (signed) "Jeffrey Smith" (signed) "Mel Belich" Jeffrey Smith Mel Belich Chairman of the Engineering, Reserves Chairman of the Board and Operations Committee March 23, 2006 -43- SCHEDULE C CHARTER OF THE AUDIT, FINANCE AND RISK COMMITTEE MANDATE OF THE COMMITTEE The Audit, Finance and Risk Committee (the "COMMITTEE") of the Board of Directors (the "BOARD") of Compton Petroleum Corporation (the "COMPANY") shall, as permitted by the Business Corporations Act (Alberta) (the "ABCA") and the Articles and By-Laws of the Company, have the responsibility to oversee that management has applied due diligence in creating and maintaining an effective risk management and control framework. This framework should provide reasonable assurance that the financial, operational, and regulatory objectives of the Company are achieved and that the statutory responsibilities of the Board are discharged. The Committee 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. The Committee has the authority to obtain independent outside accounting and other advisors as deemed appropriate to perform its duties and responsibilities. The Company shall provide appropriate funding to compensate the external auditor and any advisors that the Committee chooses to engage. The Committee is authorized to communicate directly with the external auditor to discuss and review specific issues as necessary. The Committee will primarily fulfil its responsibilities by carrying out the activities enumerated in the following sections of this Charter. The Committee will report regularly to the Board regarding the execution of its duties and responsibilities. In fulfilling its mandate, the Committee has the responsibility to, without limitation: (A) INTERNAL AND DISCLOSURE CONTROLS 1. review the effectiveness and integrity of the Company's system of disclosure controls and system of internal controls regarding finance, accounting, compliance, and ethics that management and the Board have established; 2. where the Committee considers it necessary and appropriate, set up and review an internal audit process and review any appointment or dismissal of senior internal audit personnel appointed in connection therewith; -44- 3. review the evaluation of internal controls by the external auditor with management and the Company's subsequent follow-up to any identified weaknesses; 4. review, in conjunction with the Human Resources, Compensation, Environmental, Health and Safety Committee of the Board, the appointment of the Chief Financial Officer; 5. determine the appropriate resolution of conflicts of interest in respect of audit, finance, and risk matters properly directed to the Committee; 6. review with management and the external auditor: (a) in conjunction with the report of the external auditor, the Company's audited annual financial statements, including related footnotes and management's discussion and analysis of financial conditions and results of operations ("MD&A") and quarterly financial statements, (b) the significant accounting judgments and reporting principles, practices, and procedures applied by the Company in preparing its financial statements including any newly adopted accounting policies, (c) significant changes to the audit plan, if any, and any serious disputes or difficulties with management encountered during the audit, (d) the co-operation received by the external auditor during the audit, including access to all requested records, data and information, (e) any correspondence with regulatory or governmental authorities which raises material issues regarding the Company's financial statements or accounting policies, and (f) any other matters not described above that are required to be communicated by the external auditors to the Committee pursuant to applicable law and regulation; 7. obtain an explanation from management of all significant variances between comparative reporting periods. The Committee shall review all financial statements prior to their presentation to the Board for approval; 8. review and recommend for approval by the Board, all documents to be publicly disclosed, prior to their release, which contain audited or unaudited financial information. Such documents include any prospectuses, interim unaudited financial statements, year end audited financial statements, the annual report, the annual management proxy circular, the annual information form, all press releases, and disclosures made under MD&A; 9. review with management the procedures that exist for the review of financial information extracted or derived from financial statements which is publicly disclosed by the Company other than in the documents listed in section 8 above and periodically, at least annually, assess the adequacy of those procedures, as required by Multilateral Instrument 52-110, section 2.3; 10. review with management and the external auditor all off-balance sheet financing mechanisms being used by the Company, their risks, and the clear disclosure of those risks and all other material financial risks to the Company's business; 11. discuss with the Company's General Counsel, at least annually, legal and regulatory matters that may have a material impact on the financial statements; 12. review with the Chief Financial Officer and the Chief Executive Officer of the Company their respective disclosures made to the Committee during the certification process as required by Multilateral Instrument 52-109, and in addition: -45- (a) any significant deficiencies or material weaknesses in the design or operation of internal controls, (b) any fraud involving management or other employees who have a significant role in the Company's internal controls, (c) any other obligations arising from certification, and (d) any significant changes in the internal controls; 13. review with management and the external auditor and as required by the Corporate Governance Committee, the Company's Code of Business Conduct and Ethics; 14. establish and maintain procedures for: (a) the receipt, retention, and treatment of complaints received by the Company regarding the Company's accounting, internal accounting controls, or auditing matters, and (b) the confidential and anonymous submission by Company employees of concerns regarding questionable accounting or auditing matters, and review all matters relating thereto; and 15. review with management the details of all transactions between the Company and parties related to the Company. (B) OVERSIGHT OF THE EXTERNAL AUDITOR 1. recommend to the Board and to the Shareholders the nomination of the external auditor, who shall be a "Registered Public Accounting Firm" within the meaning of applicable securities legislation, for the purpose of preparing or issuing an auditor's report or performing other audit, review, or attestation services for the Company; 2. review the qualifications and independence of the external auditor during the year; 3. at least annually, obtain and review a report by the independent auditor describing the firm's internal quality control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (to assess the auditor's independence) all relationships between the independent auditor and the listed company; 4. maintain a clear understanding with the external auditor that it is to have an open and transparent relationship with the Committee and that it is to report directly to the Committee; 5. provide a scheduled opportunity to meet with the external auditor for full, frank and timely discussions of all material issues, without management present; 6. discuss with the external auditor the scope and timing of the audit work with particular reference to high risk areas or areas of Board concern; 7. inquire as to whether the audit partner receives compensation based on the audit partner procuring engagements to provide services other than audit, review, or attest services to the Company; 8. review all reportable events, including disagreements, unresolved issues, and consultations, as defined in National Instruments 51-102, on a routine basis, whether or not there is to be a change of external auditor; -46- 9. review all issues and documentation related to a change of external auditor, including information to be included in the Change of Auditor Notice and documentation called for under National Instruments 51-102 and the planned steps for an orderly transition period; 10. appropriately supervise and evaluate the performance of the external auditor and lead audit partner, and report conclusions to the Board; 11. review and approve the Company's hiring policies regarding partners, employees, former partners, and former employees of the current and previous external auditors of the Company; 12. oversee the rotation of audit partners as required by applicable regulation and, in order to ensure continuing auditor independence, consider annually whether it is appropriate to adopt a policy of rotating the Company's external auditing firm on a regular basis; 13. pre-approve the nature of, and fees for, all audit, review, attestation, and significant non-audit services provided by the external auditor, prior to engagement, and disclose such pre-approvals in accordance with applicable securities law; 14. consider the effect of significant non-audit engagements on the independence of the external auditor; and 15. provide to the external auditor any information and explanations, and access to records, documents, books, accounts, and vouchers of the Company that are, in the opinion of the external auditor, necessary to make the examinations and reports required under legislation or regulation. (C) OVERSIGHT OF FINANCIAL REPORTING AND ACCOUNTING POLICIES 1. review with management and the external auditor significant financial reporting issues arising during the fiscal period and the methods of resolution; 2. prior to the issuance of the external auditor's report on the Company's financial statements, discuss the following with the external auditor: (a) all critical accounting policies and practices applied in the financial statements, (b) all alternative accounting and disclosure treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternate treatments and disclosures, and the treatment preferred by the external auditor, and (c) other material written communications between the external auditor and management, such as the post audit or management letter and schedule of unadjusted differences; 3. inquire of the external auditor as to the quality of the Company's accounting estimates, discussing significant judgments made in connection with the preparation of the financial statements; 4. review with management any proposed changes in major accounting policies, the impact and clear disclosure of significant risks and uncertainties, and key estimates and judgments of management that may be material to financial reporting; 5. prepare such reports and letters or other disclosure documents as are required to be prepared by the Committee under applicable securities legislation; and 6. review any notice received by the Committee with respect to an error or misstatement of which a director or officer becomes aware; -47- (D) ADDITIONAL DUTIES AND RESPONSIBILITIES 1. review the appointments of any other key financial executives who are involved in the financial reporting process; 2. review derivative and hedging policies of the Company and make recommendations to the Board in respect of gas contracts, hedging agreements, and other similar financial transactions; 3. review risk assessment and risk management policies. Such review should include the Company's major financial and accounting risk exposures, the steps management has undertaken to control them, and the clear disclosure of such material risks as part of the Company's continuous disclosure requirements; and 4. review the amount and terms of any insurance to be obtained or maintained by the Company, including insurance with respect to potential liabilities incurred by the directors or officers in the discharge of their duties and responsibilities; (E) GENERAL The Committee also has the responsibility to: 1. with the approval of the Board or the Corporate Governance Committee of the Board retain and compensate independent advisors (including legal counsel), as deemed necessary by the Committee; 2. meet separately with senior management, employees or independent advisors in respect of audit, finance and risk matters, as deemed necessary by the Committee; 3. review and assess annually the adequacy of this Charter and recommend any approved changes to the Corporate Governance Committee and the Board; 4. annually evaluate the performance of the Committee and Committee Chair; 5. prepare the Committee's report or reports for publication in applicable disclosure documents, including the Audit Committee Report for publication in the annual Management Information Circular; 6. report regularly to the Board through the Chair of the Committee or through such other person appointed by the Committee the conclusions reached and issues considered by the Committee; 7. fulfill its responsibilities and duties by: (a) inspecting any and all of the books, records, and financial affairs of the Company, its subsidiaries and affiliates, and (b) meeting with any executive or employee of the Company with or without management to review such accounts, records and other matters as any member of the Committee considers necessary and appropriate; 8. review when deemed necessary by the Committee any of the financial affairs of the Company, its subsidiaries or affiliates and make recommendations to the Board, to the external auditor, or to management, as appropriate; 9. consider and make recommendations to the Board with respect to any matters properly referred to the Committee by the Board; 10. perform any other activities consistent with this Charter as the Committee deems necessary or appropriate in order to carry out its mandate. -48- COMPOSITION OF THE COMMITTEE 1. The Committee shall be comprised of at least three directors. 2. Each member of the Committee shall be "independent" as affirmatively determined by the Board, and as defined in the Company's Standards of Independence attached hereto. 3. At least half of the members of the Committee must be resident Canadians, as that term is defined in the ABCA. 4. The Board shall appoint the members of the Committee at the first meeting of the Board following each annual meeting ("ANNUAL MEETING") of the shareholders of the Company. 5. The Board shall appoint one member of the Committee to be the Chair of the Committee. 6. A director appointed by the Board to the Committee shall be a member of the Committee until the next Annual Meeting or until his or her earlier resignation or removal by the Board. A member shall cease to be a member of the Committee upon ceasing to be a director of the Company. 7. The Board may remove or replace any member of the Committee at any time. 8. The Company's Corporate Secretary, or in his or her absence, one of the members chosen by the Committee shall be the Secretary of the Committee. 9. Members of the Committee may not serve on the audit committee of more than two additional public companies without the prior approval of the Board. 10. (a) Each member of the Committee shall be financially literate. An individual is financially literate if he or she has the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the Company's financial statements; (b) A Committee member who is not financially literate may be appointed to the Committee provided that the member becomes financially literate within a reasonable period of time following his or her appointment; and (c) At least one member of the Committee shall have accounting or related financial management expertise and, where possible, at least one member of the Committee shall qualify as an "audit committee financial expert" within the meaning of applicable securities legislation. MEETINGS OF THE COMMITTEE 1. The Committee shall convene at such times and places designated by the Chair of the Committee, at least on a quarterly basis, and whenever a meeting is requested by the Board, a member of the Committee, the external auditor, or a senior officer of the Company. The Committee shall meet in separate sessions with management and the external auditor at each regularly scheduled meeting. 2. Notice of each meeting of the Committee shall be given to each member and to the external auditor, who shall be entitled to attend each meeting of the Committee. -49- 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. -50- COMPTON PETROLEUM CORPORATION STANDARDS OF INDEPENDENCE Compton Petroleum Corporation ("Compton" or "the Company") has adopted the following standards for determining whether a director is independent within the meaning of applicable Canadian and United States securities laws and the New York Stock Exchange corporate governance rules. These Standards will be periodically reviewed and may be modified by Compton's Board of Directors ("the Board"). Except where required by applicable law or the rules of the New York Stock Exchange, the criteria set forth in these standards are not intended to constitute rigid rules that govern the Board's determination of whether a director is independent from the Company or an interpretation of any applicable law, rule or regulation. To be considered independent for purposes of these standards, the Board must affirmatively determine on an annual basis that the director being reviewed has no direct or indirect material relationship with the Company. A "material relationship" is a relationship which could, in the view of the Company's Board, be reasonably expected to interfere with the exercise of a member's independent judgment. In each case, the Board shall consider all relevant facts and circumstances. Additionally, a director will not be deemed to be independent if: (a) the director is, or has been within the last three years, an employee or executive officer of the Company, or an immediate family member(1) of the director is, or has been within the last three years, an executive officer of the Company; (b) the director is a current partner or employee of a firm that is the Company's internal or external auditor, or was within the last three years, a partner(2) or employee of that firm and personally worked on the Company's audit within that time; (c) an immediate family member of the director is a current partner of a firm that is the Company's internal or external auditor, or is a current employee of that firm and participates in its audit, assurance or tax compliance (but not tax planning) practice, or was, within the last three years a partner or employee of that firm and personally worked on the Company's audit within that time; (d) the director, or an immediate family member of the director, is or has been within the last three years, an executive officer of an entity on which any of the Company's current executive officers serves or served at that same time on the entity's compensation committee; (e) the director or an immediate family member of the director who is employed as an executive officer of the Company has received, during any twelve month period within the last three years, more than $75,000 in direct compensation from the Company, other than 1) director and committee fees, 2) pension or other forms of deferred compensation for prior service provided that such compensation is not contingent in any way on continued service and 3) compensation for previously acting as an interim chief executive officer of the Company or previously acting as a chairman of the board on a part-time basis; (f) the director is a current employee, or an immediate family member is a current executive officer, of a company that has made payments to, or received payments from, the Company for property or services in an amount which, in any of the last three fiscal years, exceeds the greater of $1 million, or 2% of such other company's consolidated gross revenues; (g) the director accepts, directly or indirectly, any consulting, advisory or other compensatory fee from the Company or any subsidiary entity of the Company, other than as remuneration for acting in the director's capacity as a member of the board or any board committee, or as a part-time chair or vice-chair of the board or any board committee; or is an affiliated entity of the Company or any of its subsidiary entities. Other compensatory fees includes acceptance of a fee by an immediate family member or an entity in which the director is a partner, member, an officer such as a managing director occupying a comparable position or executive officer, or occupies a similar position (except limited partners, non-managing members and those -51- occupying similar positions who, in each case, have no active role in providing services to the entity) and which provides accounting, consulting, legal, investment banking or financial advisory services to the Company or any subsidiary entity of the Company. Compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the Company if the compensation is not contingent in any way on continued service. (h) the director is an affiliated(3) person of the Company. (1) An immediate family member is defined as a director's spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law, brothers and sisters-in-law, and anyone (other than domestic employees) who shares the director's home. (2) A partner does not include a fixed income partner whose interest in the firm that is the internal or external auditor is limited to the receipt of fixed amounts of compensation (including deferred compensation) for prior service with that firm if the compensation is not contingent in any way on continued service. (3) Affiliated person of another person means: (a) any person directly or indirectly owning, controlling, or holding with power to vote, 5% or more of the outstanding voting securities of such other person; (b) any person 5% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by such other person; (c) any person directly or indirectly controlling, controlled by, or under common control with, such other person; (d) any officer, director, partner, copartner, or employee of such other person; (e) if such other person is an investment company, any investment adviser thereof or any member of an advisory board thereof; and (f) if such other person is an unincorporated investment company not having a board of directors, the depositor thereof.