F-4/A 1 formf4-a1.txt FORM F-4 AMENDMENT NO. 1 As filed with the Securities and Exchange Commission on September 19, 2002 Registration No. 333-96537 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------------------- AMENDMENT NO. 1 TO FORM F-4 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ---------------------------------- COMPTON PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) PROVINCE OF ALBERTA, CANADA 1311 NOT APPLICABLE (State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer of incorporation or Classification Code Number) Identification Number) organization) SUITE 3300, 425 - 1ST STREET S.W. CALGARY, ALBERTA, CANADA T2P 3L8 (403) 237-9400 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) ---------------------------------- HORNET ENERGY LTD. (Exact name of registrant as specified in its charter) 867791 ALBERTA LTD. (Exact name of registrant as specified in its charter) 899776 ALBERTA LTD. (Exact name of registrant as specified in its charter) COMPTON PETROLEUM (Exact name of registrant as specified in its charter) PROVINCE OF ALBERTA, CANADA 1311 NOT APPLICABLE (State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer of incorporation or Classification Code Number) Identification Number) organization) SUITE 3300, 425 - 1ST STREET S.W. CALGARY, ALBERTA, CANADA T2P 3L8 (403) 237-9400 (Name, address, including zip code, and telephone number, including area code, of registrant's principal executive offices) ---------------------------------- CT CORPORATION SYSTEM 111 EIGHTH AVENUE NEW YORK, NY 10011 (212) 894-8940 (Name, address, including zip code, and telephone number, including area code, of agent for service) ---------------------------------- WITH COPIES TO: ANDREW J. FOLEY, ESQ. DAVID LEFEBVRE, ESQ. PAUL, WEISS, RIFKIND, WHARTON & GARRISON FRASER, MILNER & CRASGRAIN, LLP 1285 AVENUE OF THE AMERICAS 30TH FLOOR, FIFTH AVENUE PLACE NEW YORK, NEW YORK 10019-6064 237-4TH AVENUE S.W. (212) 373-3000 CALGARY, ALBERTAT2P 4X7, CANADA (403) 268-7000 ---------------------------------- APPROXIMATE DATE OF COMMENCEMENT OF SALE TO THE PUBLIC: AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT IS DECLARED EFFECTIVE. ---------------------------------- If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.
CALCULATION OF REGISTRATION FEE =================================================================================================================================== TITLE OF EACH CLASS OF AMOUNT TO BE PROPOSED MAXIMUM OFFERING PROPOSED MAXIMUM AGGREGATE AMOUNT OF SECURITIES TO BE REGISTERED REGISTERED PRICE PER UNIT(1)(2) OFFERING PRICE(1)(2) REGISTRATION FEE(3) ----------------------------------------------------------------------------------------------------------------------------------- 9.90% notes due 2009............. $165,000,000 100% $ 165,000,000 $ 15,180 ----------------------------------------------------------------------------------------------------------------------------------- Guarantees of Notes.............. -------------- ----------------- --------------- ------------ ===================================================================================================================================
(1) Determined solely for the purpose of calculating the registration fee in accordance with Rule 457 promulgated under the Securities Act of 1933, as amended. (2) No separate consideration will be received for the subsidiary guarantees. (3) Pursuant to Rule 457(n), no separate fee for the subsidiary guarantees is payable. ---------------------------------- THE REGISTRANTS HEREBY AMEND THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANTS SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. ================================================================================ PART I INFORMATION REQUIRED TO BE DELIVERED TO OFFEREES OR PURCHASERS The information in this prospectus is not complete and may be changed. We may not sell these securities or accept any offer to sell these securities until we deliver this prospectus to you in final form. We are not using this prospectus to offer to sell these securities or to solicit offers to buy these securities in any place where the offer or sale is not permitted. PROSPECTUS [GRAPHIC OMITTED] COMPTON ------------------------------------ PETROLEUM CORPORATION EXCHANGE OFFER OF US$165,000,000 OF OUR 9.90% SENIOR NOTES DUE 2009 -------------------------------------------------------------------------------- TERMS OF THE EXCHANGE OFFER: o It will expire at 5:00 p.m., New York City time, on __________2002, unless we extend it. o If all the conditions to this exchange offer are satisfied, we will exchange all of our 9.90% Senior Notes due 2009 issued on May 8, 2002, which we refer to as the initial notes, that are validly tendered and not withdrawn for new notes, which we refer to as the exchange notes. o You may withdraw your tender of initial notes at any time before the expiration of this exchange offer. o The exchange notes that we will issue to you in exchange for your initial notes will be substantially identical to your initial notes except that, unlike your initial notes, the exchange notes will have no transfer restrictions or registration rights. o The exchange notes that we will issue to you in exchange for your initial notes are new securities with no established market for trading. BEFORE PARTICIPATING IN THIS EXCHANGE OFFER, PLEASE REFER TO THE SECTION IN THIS PROSPECTUS ENTITLED "RISK FACTORS" COMMENCING ON PAGE 13. Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. -------------------------------------------------------------------------------- The date of this prospectus is ____________, 2002. TABLE OF CONTENTS PROSPECTUS SUMMARY.............................................................3 RISK FACTORS..................................................................13 ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS...................20 CURRENCY TRANSLATION..........................................................20 FORWARD-LOOKING STATEMENTS....................................................21 USE OF PROCEEDS...............................................................21 CAPITALIZATION................................................................22 SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA...............................23 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.............................................24 BUSINESS......................................................................35 MANAGEMENT....................................................................47 RELATED PARTY TRANSACTIONS....................................................50 SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT........................51 DESCRIPTION OF OTHER INDEBTEDNESS.............................................52 THE EXCHANGE OFFER............................................................53 DESCRIPTION OF THE EXCHANGE NOTES.............................................60 DESCRIPTION OF THE INITIAL NOTES..............................................96 BOOK-ENTRY, DELIVERY AND FORM.................................................96 MATERIAL INCOME TAX CONSIDERATIONS............................................99 PLAN OF DISTRIBUTION.........................................................102 LEGAL MATTERS................................................................103 INDEPENDENT PETROLEUM ENGINEERS..............................................103 INDEPENDENT ACCOUNTANTS......................................................103 WHERE YOU CAN FIND MORE INFORMATION..........................................103 FINANCIAL STATEMENTS INDEX ..................................................F-1 --------------------------------------------------------- -2- PROSPECTUS SUMMARY THE FOLLOWING SUMMARY IS QUALIFIED IN ITS ENTIRETY BY AND SHOULD BE READ IN CONJUNCTION WITH THE DETAILED INFORMATION AND FINANCIAL STATEMENTS APPEARING ELSEWHERE IN THIS PROSPECTUS. YOU SHOULD READ THE ENTIRE PROSPECTUS CLOSELY. THE TERMS "COMPTON", "WE", "OUR" AND "US", EXCEPT AS OTHERWISE INDICATED IN THIS PROSPECTUS OR AS THE CONTEXT OTHERWISE INDICATES, REFER TO COMPTON PETROLEUM CORPORATION AND OUR SUBSIDIARIES AS A COMBINED ENTITY. THE TERM "INITIAL NOTES" REFERS TO THE 9.90% SENIOR NOTES DUE 2009 THAT WERE ISSUED ON MAY 8, 2002 IN A PRIVATE OFFERING. THE TERM "EXCHANGE NOTES" REFERS TO THE 9.90% SENIOR NOTES DUE 2009 OFFERED WITH THIS PROSPECTUS. EXCEPT AS OTHERWISE PROVIDED HEREIN, THE TERM "NOTES" REFERS TO THE INITIAL NOTES AND THE EXCHANGE NOTES, COLLECTIVELY. UNLESS OTHERWISE INDICATED, ALL REFERENCES TO "$" IN THIS PROSPECTUS REFER TO CANADIAN DOLLARS AND ALL REFERENCES TO "US$" REFER TO UNITED STATES DOLLARS. THE COMPANY We are an independent public company actively engaged in the exploration, development and production of natural gas, natural gas liquids and crude oil in western Canada. We have established our current operational base through a combination of a program of full-cycle exploration and strategic acquisitions. This involves: o establishing core geographic operating areas through strategic acquisitions; o developing significant operational and technical expertise through exploration and development activities; o acquiring strategic control over infrastructure; and o reinvesting operating cash-flow to further consolidate our position in each of our core areas and to further grow our inventory of drilling prospects. We began operations in 1993 with a small technical team and a large seismic database. Through a series of acquisitions and continued drilling success, we have established total proved reserves of 321 bcfe as of December 31, 2001. Approximately 82% of our total proved reserves are natural gas and approximately 89% of our total proved reserves are proved developed. As of June 30, 2002, we held working interests in 826,591 (635,371 net) acres of undeveloped land and we held working interests in 1,056 gross (437.2 net) producing wells in western Canada. We currently focus our operations in four geographic areas: o SOUTHERN ALBERTA-- ESTABLISHED IN 1993: We have one of the largest land positions in the area, with more than 452,488 net acres (330,001 net undeveloped acres) of gas-prone lands. Concentrated in and around our net acreage, there are approximately 1,800,000 acres or 2,850 sections of land. We own approximately 25% of these lands, which represents the largest percentage of land ownership among oil and gas companies operating within this area. These lands are primarily gas-prone, with 64% of producing wells within the area being natural gas wells. We operate substantially all of our production and have long-term access to necessary processing facilities in this area. We believe that our land ownership position in this area will provide us with a multi-year inventory of exploration and development prospects. This area represented 69% of our proved reserves as of December 31, 2001, 52% of our net undeveloped land as of June 30, 2002, 53% of our production for the year ended December 31, 2001 and 55% of our production for the six months ended June 30, 2002. o WEST CENTRAL ALBERTA -- ESTABLISHED IN 1998: This area has significant natural gas and light oil production. We plan to increase our long-life, high-quality, light oil production through a variety of exploitation techniques and to pursue multi-zone gas exploration targets. This area represented 17% of our proved reserves as of December 31, 2001, 18% of our net undeveloped land as of June 30, 2002, 26% of our production for the year ended December 31, 2001 and 24% of our production for the six months ended June 30, 2002. -3- o PEACE RIVER ARCH-- ESTABLISHED IN 1998: This north-central Alberta core area offers us a range of opportunities, including lower-risk exploitation, secondary recovery efforts and pure natural gas exploration. Our light oil development program, which consists of secondary recovery through water flooding of the reservoir and infill drilling, provides us with predictable ongoing production and an extension of the area's reserve life. We plan to expand and consolidate our operations in this core area by acquiring additional land and increasing control of operatorship and infrastructure. This area represented 13% of our proved reserves as of December 31, 2001, 10% of our net undeveloped land as of June 30, 2002, 18% of our production for the year ended December 31, 2001 and 19% of our production for the six months ended June 30, 2002. o NORTHERN ALBERTA-- ESTABLISHED IN 1996: Within the Rainbow/Zama area in northern Alberta, we have a large undeveloped land base consisting of more than 96,000 net acres that we believe provides us with multi-zone exploration opportunities. This area is relatively under-explored due to its remoteness. Industry interest, however, has heightened with increased drilling and infrastructure activity on lands adjacent to ours. Since 1996, drilling activity and infrastructure construction has increased considerably in the Rainbow/Zama area. In 1996, a total of 63 wells were drilled by the oil and gas industry, as compared to approximately 225 wells in fiscal 2001. Moreover, a major natural gas pipeline was installed in fiscal 2000 which transports gas through our main block of lands. More recently, two other oil and gas companies have installed natural gas gathering pipelines in the area. This area represented 1% of our proved reserves as of December 31, 2001, 15% of our net undeveloped land as of June 30, 2002, 3% of our production for the year ended December 31, 2001 and 2% of our production for the six months ended June 30, 2002. In addition to our four core areas discussed above, we have 5% of our net undeveloped land in minor properties outside of our four geographic core areas. These lands are located in northeastern British Columbia, northeastern Saskatchewan and southern Manitoba. These minor properties were acquired primarily as a result of acquisitions of corporations whose primary assets were in one or more of our core areas. Currently, less than 1% of our production comes from these minor properties. BUSINESS STRATEGY Our strategy is to grow our reserves and increase our production in our four core geographic areas and other areas where we have technical expertise. Our senior management team has significant technical and operational expertise with an average of 20 years of experience in one or more of our core areas. CONCENTRATE ON FOUR CORE GEOGRAPHIC AREAS. We currently operate in four core geographic areas which provides us with a balanced portfolio of exploration and development prospects. FOCUS ON NATURAL GAS. We have gained considerable technical expertise and achieved significant success in exploring for deeper and larger natural gas reservoirs. In 2001, our average well depth was approximately 1,790 meters, which is significantly deeper than the Alberta oil and gas industry average well depth of approximately 1,000 meters. Notwithstanding our increased focus on drilling for deeper gas reservoirs, we were able to achieve a drilling success rate of 76% in 2001, as compared to our drilling success rate of 61% in 1998. We plan to continue to focus on finding and developing long-life natural gas reserves. Our proved reserves as of December 31, 2001 of 321 bcfe were approximately 82% natural gas with an estimated reserve life of 8.2 years at that date. PURSUE FULL-CYCLE EXPLORATION COMPLEMENTED BY SELECTIVE ACQUISITIONS. We plan to continue to reinvest internally generated cash flow to fund the growth of our exploration prospects and development projects and to further consolidate our undeveloped land base to maintain a growing inventory of drilling prospects in our core geographic areas. CONTROL OF INFRASTRUCTURE AND OPERATORSHIP. We believe that control over gathering and processing infrastructure and operatorship of drilling programs will continue to be critical to the success of our full-cycle exploration program. MAINTAIN A LARGE PORTFOLIO OF UNDEVELOPED LAND. We have assembled a significant portfolio of undeveloped land (working interests in 826,591 (635,371 net) acres of undeveloped land, as of June 30, 2002) and complementary seismic data in our core areas. MAINTAIN FINANCIAL FLEXIBILITY. We are committed to maintaining financial flexibility to allow us to pursue our full-cycle exploration program in periods of low commodity prices. -4- RECENT DEVELOPMENTS Our average daily production for the first six months of 2002 was 19,193 boe/d, an increase of 13% over the 17,009 boe/d for the comparable period in 2001. Commodity prices realized during the period, however, were significantly lower than the historically high prices realized during the first six months of 2001. Both the West Texas Intermediate oil benchmark price and the AECO natural gas price index decreased substantially from the first six months of 2001, down 16% and 57%, respectively. "AECO" refers to the price of natural gas located at a reference sales point storage facility in the province of Alberta. This dramatic drop in commodity prices had an adverse impact on our earnings and cash flow for the first six months of 2002. REGULATORY REQUIREMENTS Other than under the U.S. securities laws, we are not required to obtain any regulatory approvals relating to the issuance of the exchange notes. We will be required, however, to comply with all applicable U.S. federal securities laws and any securities or blue sky laws of the various states. ----------------------------------------------------- We were incorporated under the BUSINESS CORPORATIONS ACT (Alberta) in 1992 and we commenced active business operations in July 1993. Our principal executive offices are located at Suite 3300, 425 - 1st Street S.W., Calgary, Alberta, T2P 3L8. Our general telephone number is (403) 237-9400 and our website is located at WWW.COMPTONPETROLEUM.COM. The information on our website is not part of this prospectus. Our common shares are listed and posted for trading on The Toronto Stock Exchange under the trading symbol "CMT". -5- SUMMARY OF THE EXCHANGE OFFER We are offering to exchange US$165,000,000 aggregate principal amount of our exchange notes for a like aggregate principal amount of our initial notes. In order to exchange your initial notes, you must properly tender them and we must accept your tender. We will exchange all outstanding initial notes that are validly tendered and not validly withdrawn. Exchange Offer...................... We will exchange our exchange notes for a like aggregate principal amount at maturity of our initial notes. Expiration Date..................... This exchange offer will expire at 5:00 p.m., New York City time, on ______, 2002, unless we decide to extend it. Conditions to the Exchange Offer.... We will complete this exchange offer only if: o there is no change in the laws and regulations which would impair our ability to proceed with this exchange offer; o there is no change in the current interpretation of the staff of the Securities and Exchange Commission (the "Commission") which permits resales of the exchange notes; o there is no stop order issued by the Commission which would suspend the effectiveness of the registration statement which includes this prospectus or the qualification of the exchange notes under the TRUST INDENTURE ACT OF 1939; o there is no litigation or threatened litigation which would impair our ability to proceed with this exchange offer; and o we obtain all the governmental approvals we deem necessary to complete this exchange offer. Please refer to the section in this prospectus entitled "The Exchange Offer -- Conditions to the Exchange Offer". Please refer to the section in this prospectus entitled "The Exchange Offer -- Conditions to the Exchange Offer." Procedures for Tendering Initial To participate in this exchange offer, Notes....................... you must complete, sign and date the letter of transmittal or its facsimile and transmit it, together with your initial notes to be exchanged and all other documents required by the letter of transmittal, to The Bank of Nova Scotia Trust Company of New York, as exchange agent, at its address indicated under "The Exchange Offer-- Exchange Agent." In the alternative, you can tender your initial notes by book-entry delivery following the procedures described in this prospectus. If your initial notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, you should contact that person promptly to tender your initial notes in this exchange offer. For more information on tendering your notes, please refer to the section in this prospectus entitled "The Exchange Offer-- Procedures for Tendering Initial Notes." Special Procedures for Beneficial If you are a beneficial owner of Owners...................... initial notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your initial notes in the exchange offer, you should contact the registered holder promptly and instruct that person to tender on your behalf. Guaranteed Delivery Procedures .... If you wish to tender your initial notes and you cannot get the required documents to the exchange agent on time, you may tender your notes by using the guaranteed delivery procedures described under the section of this prospectus entitled "The Exchange Offer-- Procedures for Tendering Initial Notes-- Guaranteed Delivery Procedure." Withdrawal Rights................... You may withdraw the tender of your initial notes at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer. To withdraw, you must send a written or facsimile transmission notice of withdrawal to the exchange agent at its address indicated under "The Exchange Offer-- Exchange Agent" before 5:00 -6- p.m., New York City time, on the expiration date of the exchange offer. Acceptance of Initial Notes and If all the conditions to the completion Delivery of Exchange Notes....... of this exchange offer are satisfied, we will accept any and all initial notes that are properly tendered in this exchange offer on or before 5:00 p.m., New York City time, on the expiration date. We will return any initial note that we do not accept for exchange to you without expense as promptly as practicable after the expiration date. We will deliver the exchange notes to you as promptly as practicable after the expiration date and acceptance of your initial notes for exchange. Please refer to the section in this prospectus entitled "The Exchange Offer -- Acceptance of Initial Notes for Exchange; Delivery of Exchange Notes." Federal Income Tax Considerations Exchanging your initial notes for Relating to the Exchange Offer... exchange notes will not be a taxable event to you for United States federal income tax purposes. Please refer to the section of this prospectus entitled "Material Income Tax Considerations-- U.S. Federal Income Tax Considerations". Exchange Agent...................... The Bank of Nova Scotia Trust Company of New York is serving as exchange agent in the exchange offer. Fees and Expenses................... We will pay all expenses related to this exchange offer. Please refer to the section of this prospectus entitled "The Exchange Offer-- Fees and Expenses". Use of Proceeds..................... We will not receive any proceeds from the issuance of the exchange notes. We are making this exchange offer solely to satisfy certain of our obligations under our registration rights agreement entered into in connection with the offering of the initial notes. The net proceeds to us from the offering of the initial notes were approximately US$156.3 million, after deducting the initial purchasers' discount and offering expenses. We used the proceeds from the offering to repay our outstanding debt under our senior credit facilities. The remaining net proceeds, approximately US$5.7 million, were used for general corporate purposes. Consequences to Holders Who Do If you do not participate in this Not Participate in the Exchange exchange offer: Offer............................ o you will not necessarily be able to require us to register your initial notes under the U.S. SECURITIES ACT OF 1933 (the "Securities Act"); o you will not be able to resell, offer to resell or otherwise transfer your initial notes unless they are registered under the Securities Act or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act; and o the trading market for your initial notes will become more limited to the extent other holders of initial notes participate in the exchange offer. Please refer to the section of this prospectus entitled "Risk Factors -- Your failure to participate in the exchange offer will have adverse consequences." Resales............................. It may be possible for you to resell the notes issued in the exchange offer without compliance with the registration and prospectus delivery provisions of the Securities Act, subject to some conditions. Please refer to the section of this prospectus entitled "Risk Factors-- Risks Relating to the Exchange Offer-- Some persons who participate in the exchange offer must deliver a prospectus in connection with resales of the exchange notes" and "Plan of Distribution". -7- THE EXCHANGE NOTES THIS SUMMARY DESCRIBES THE PRINCIPAL TERMS OF THE EXCHANGE NOTES. SOME OF THE TERMS AND CONDITIONS DESCRIBED BELOW ARE SUBJECT TO IMPORTANT LIMITATIONS AND EXCEPTIONS. YOU SHOULD CAREFULLY READ THE "DESCRIPTION OF THE EXCHANGE NOTES" SECTION OF THIS PROSPECTUS FOR A MORE DETAILED DESCRIPTION OF THE OFFERING. Company............................. Compton Petroleum Corporation. Exchange Notes...................... US$165.0 million aggregate principal amount of 9.90% Senior Notes due 2009. The forms and terms of the exchange notes are the same as the form and terms of the initial notes except that the issuance of the exchange notes is registered under the Securities Act, the exchange notes will not bear legends restricting their transfer and will not be entitled to registration rights under our registration rights agreement. The exchange notes will evidence the same debt as the initial notes, and both the initial notes and the exchange notes will be governed by the same indenture. Maturity Date....................... May 15, 2009. Interest............................ 9.90% per year. We will make interest payments in U.S. dollars. Interest Payment Dates.............. May 15 and November 15, beginning on November 15, 2002. Mandatory Redemption................ We will not be required to make mandatory redemption or sinking fund payments with respect to the notes. Optional Redemption................. We may redeem the notes in whole or in part at any time on or after May 15, 2006, at the redemption prices described under "Description of the Exchange Notes-- Optional Redemption". Prior to May 15, 2005, we may redeem up to 35% of the notes with the proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the notes under the indenture remains outstanding after the redemption and subject to limitations contained in our senior credit facilities. Redemption for Changes in We will make payments on the notes free Canadian Withholding Taxes....... of withholding or deduction for Canadian taxes. If withholding or deduction is required, we will be required to pay additional amounts so that the net amounts you receive will equal the amount you would have received if withholding or deduction had not been imposed. If, as a result of a change in law occurring after the date of the offering, we are required to pay such additional amounts, we may redeem the notes in whole but not in part, at any time at 100% of their principal amount, plus accrued and unpaid interest, if any, to the redemption date. Guarantees.......................... All payments with respect to the notes, including principal and interest, will be fully and unconditionally guaranteed on an unsecured senior basis by all of our current subsidiaries and future restricted subsidiaries, enforceable against all of these subsidiaries collectively or against any of them individually. Should a future restricted subsidiary of ours guarantee the notes, this guarantee will constitute a new issuance of securities under the Securities Act and will require us to register such issuance under the Securities Act or effect such issuance under an exemption from registration. Each of our guarantors also guarantees our senior credit facilities on a senior secured basis. Change of Control................... Upon specified change of control events, each holder of a note will have the right to sell to us all or a portion of its notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest, if any, to the date of repurchase. Ranking............................. The notes and the guarantees will be: -8- o unsecured; o equal in right of payment to our and our guarantor subsidiaries' current and future unsecured senior indebtedness; o senior in right of payment to our and our guarantor subsidiaries' future debt that expressly provides for subordination to the notes or the guarantees; and o effectively subordinated in right of payment to any of our and our guarantor subsidiaries' senior credit facilities which are secured by substantially all of our and our guarantors' assets. Covenants........................... The indenture governing the notes will limit our ability and that of our restricted subsidiaries to, among other things: o incur additional indebtedness and issue preferred stock; o create liens; o make restricted payments; o impose restrictions on the ability of restricted subsidiaries to make specified payments and distributions; o make material dispositions of assets; o engage in transactions with affiliates; o engage in specified business activities; and o engage in mergers, consolidations and certain transfers of assets. These covenants are subject to important exceptions and qualifications, as described under "Description of the Exchange Notes". Registration Rights Agreement....... Under a registration rights agreement, we have agreed to file a registration statement on an appropriate form with respect to this offer to exchange the initial notes for the exchange notes, which will be registered under the Securities Act. This prospectus is part of that registration statement. Use of Proceeds..................... We will not receive any proceeds from the issuance of the exchange notes in exchange for the outstanding initial notes. We are making this exchange solely to satisfy our obligations under the registration rights agreement entered into in connection with the offering of the initial notes. Absence of a Public Market for the The exchange notes are new securities Exchange Notes................... with no established market for them. We cannot assure you that a market for these exchange notes will develop or that this market will be liquid. Please refer to the section of this prospectus entitled "Risk Factors -- Risks Relating to the Exchange Offer". Form of the Exchange Notes.......... The exchange notes will be represented by one or more permanent global securities in registered form deposited on behalf of The Depository Trust Company with The Bank of Nova Scotia Trust Company of New York, as custodian. You will not receive exchange notes in certificated form unless one of the events described in the section of this prospectus entitled "Description of the Exchange Notes-- Book Entry; Delivery and Form-- Exchange of Book Entry Notes for Certificated Notes" occurs. Instead, beneficial interests in the exchange notes will be shown on, and transfers of these exchange notes will be effected only through, records maintained in book-entry form by The Depository Trust Company with respect to its participants. -9- SUMMARY RESERVE AND UNDEVELOPED LAND DATA The following table summarizes our undeveloped land and our natural gas, crude oil and natural gas liquids reserves as of the dates indicated and the present value attributable to the reserves as of those dates, discounted at 10%. The reserve information as of December 31, 2001 was prepared by Outtrim Szabo Associates Ltd. The reserve information as of December 31, 1999 and 2000 was prepared by or reviewed by Outtrim Szabo Associates Ltd.
HISTORICAL ------------------------------------------ AS OF DECEMBER 31, ------------------------------------------ 1999 2000 2001 ------------ ------------ ------------ PROVED RESERVES: Natural gas (mmcf).................. 181,759 223,761 262,448 Crude oil & natural gas liquids (mbbls) 10,682 9,423 9,777 Natural gas equivalent (mmcfe).... 245,851 280,302 321,110 % natural gas..................... 74% 80% 82% % proved developed................ 85% 85% 89% Estimated reserve life (in years)(1) 8.9 7.9 8.2 Annual reserve replacement ratio(2). 268% 197% 204% Recycle ratio(3).................... 1.2x 2.2x 1.5x PV-10 (thousands of dollars)(4)..... $ 393,448 $ 1,227,443 $ 465,619 Standardized measure of discounted future net cash flows (thousands of dollars)............................ $ 271,486 $ 709,869 $ 317,461 UNDEVELOPED LAND Gross undeveloped land (thousands of acres)............................ 707 808 962 Working interest percentage......... 71% 76% 73%
------------------------ (1) Reserve life is calculated by dividing our proved reserves at year end by our annual production in that year. (2) The annual reserve replacement ratio is a percentage determined by dividing our estimated proved reserves added during a year from exploitation, development and exploration activities, acquisition of proved reserves and revisions of previous estimates, excluding property sales, by our annual production in that year. (3) The recycle ratio is a multiple determined by dividing our netback per boe by our finding and development costs per boe in that year. Netback per boe is calculated by dividing our annual net revenues generated from producing oil and natural gas volumes, net of operating costs and administrative expenses by our annual production in that year. Finding and development costs per boe is calculated by dividing our estimated finding and development costs associated with our estimated proved reserves added during the year by our estimated proved reserves added in that year from exploitation, development and exploration activities, acquisition of proved reserves and revisions of previous estimates, excluding property sales. (4) PV-10 is the present value of our estimated future net cash flows before income taxes, discounted at 10% per year, calculated using constant pricing. The prices used in 1999 were $2.88 per mcf of natural gas, $36.64 per barrel of crude oil and $30.88 per barrel of natural gas liquids. The prices used in 2000 were $9.69 per mcf of natural gas, $39.33 per barrel of crude oil and $37.57 per barrel of natural gas liquids. The prices used in 2001 were $3.68 per mcf of natural gas, $32.63 per barrel of crude oil and $22.98 per barrel of natural gas liquids. PV-10 is not necessarily indicative of actual future cash flows. -10- SUMMARY OPERATING DATA The following provides summary data with respect to our production and sales of crude oil and natural gas for the periods indicated and the costs related to such production.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------ --------------------- 1999 2000 2001 2001 2002 -------- ------- ------- -------- ---------- PRODUCTION: Natural gas (mmcf)................... 19,834 25,039 28,405 13,315 15,469 Natural gas liquids (mbbls).......... 463 528 506 215 294 Crude oil (mbbls).................... 841 1,235 1,320 645 602 Natural gas equivalent (mmcfe).... 27,653 35,618 39,363 18,471 20,843 AVERAGE SALES PRICE PER UNIT: Natural gas (per mcf)................ $ 2.62 $ 4.54 $ 4.77 $ 6.69 $ 3.26 Natural gas liquids (per bbl)........ 16.27 25.12 20.80 22.95 18.38 Crude oil (per bbl).................. 25.43 33.82 32.55 36.45 32.44 Natural gas equivalent (per mcfe). 2.93 4.74 4.80 6.36 3.62 COSTS: Operating (per mcfe)................. $ 0.74 $ 0.89 $ 1.02 $ 1.00 $ 1.05 General and administrative (per mcfe) 0.15 0.17 0.16 0.20 0.21
-11- DEFINITIONS AND OTHER MATTERS As used in this prospectus, the following terms have the meaning indicated: o "AECO" means the price of natural gas located at a reference sales point storage facility in the province of Alberta; o "bbls" and "mbbls" mean barrels and thousand barrels, respectively; o "boe" and "mboe" mean barrels of oil equivalent and thousand barrels of oil equivalent, respectively; o "bbls/d", "mcf/d", "mmcf/d" and "boe/d" mean barrels per day, thousand cubic feet per day, million cubic feet per day and barrels of oil equivalent per day, respectively; o "developed land" means acreage on which we have a productive well; o "farm-in" means an arrangement whereby one person or entity carries out drilling operations on certain crude oil and natural gas properties owned by another to earn an ownership interest in those properties; o "GJ" means gigajoule; o "GJ/d means gigajoules per day; o "light oil" means crude oil with an American Petroleum Institute (API) gravity score that is 26 or greater; o "mcf", "mmcf" and "bcf" mean thousand cubic feet, million cubic feet and billion cubic feet, respectively; o "mcfe", "mmcfe" and "bcfe" means thousand cubic feet equivalent, million cubic feet equivalent and billion cubic feet equivalent, respectively; o "production" means production attributable to our interest after deducting royalties; o "proved developed" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional crude oil and natural gas expected to be obtained through the application of fluid injection, or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery, are included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved; o "proved reserves" are the estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir; -12 (ii) reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources; and o "undeveloped land" means acreage on which we do not have a productive well and includes exploratory acreage. Natural gas volumes are converted to barrels of oil equivalent using the ratio of 6 thousand cubic feet of natural gas to one barrel of oil and are stated at the official temperature and pressure bases of the area in which the reserves are located. Proved reserve volumes have been determined after deducting royalties. PRESENTATION OF FINANCIAL INFORMATION The historical financial statements contained in this prospectus are reported in Canadian dollars and have been prepared in accordance with Canadian generally accepted accounting principles. Note 17 to our historical consolidated financial statements contained in this prospectus summarizes the differences between generally accepted accounting principles in Canada and the United States. RISK FACTORS YOU SHOULD CAREFULLY CONSIDER THE FOLLOWING MATTERS, AS WELL AS THE OTHER INFORMATION CONTAINED IN THIS PROSPECTUS, BEFORE TENDERING YOUR INITIAL NOTES IN THE EXCHANGE OFFER. INFORMATION CONTAINED IN THIS PROSPECTUS CONTAINS "FORWARD-LOOKING STATEMENTS", WHICH ARE QUALIFIED BY THE INFORMATION CONTAINED IN THE SECTION OF THIS PROSPECTUS ENTITLED "FORWARD-LOOKING STATEMENTS". IF ANY OF THE RISKS DESCRIBED BELOW MATERIALIZE, OUR ABILITY TO SATISFY OUR OBLIGATIONS TO THE HOLDERS OF THE EXCHANGE NOTES AND THE TRADING PRICE OF THE EXCHANGE NOTES COULD BE ADVERSELY AFFECTED. RISKS RELATED TO OUR BUSINESS OIL AND NATURAL GAS PRICES ARE VOLATILE AND LOW PRICES WILL ADVERSELY AFFECT OUR BUSINESS. Fluctuations in the prices of oil and natural gas will affect many aspects of our business, including: o our revenues, cash flows and earnings; o our ability to attract capital to finance our operations; o our cost of capital; o the amount we are allowed to borrow under our senior credit facilities; and o the value of our oil and natural gas properties. Both oil and natural gas prices are extremely volatile. Oil prices are determined by international supply and demand. Political developments, compliance or non-compliance with self-imposed quotas or agreements between members -13- of the Organization of Petroleum Exporting Countries can affect world oil supply prices. Any material decline in prices could result in a reduction of our production revenue and overall value. The economics of producing from some wells could change as a result of lower prices. As a result, we could elect not to produce from certain wells. Any material decline in prices could also result in a reduction in our oil and natural gas acquisition and development activities. Natural gas and oil prices have declined substantially since fiscal 2000. The AECO spot price of natural gas was $3.00 per GJ on June 30, 2001 and has decreased to $2.06 per GJ on June 30, 2002. Average natural gas prices realized by us in fiscal 2000 were $4.54 per mcf and average natural gas prices in fiscal 2001 were $4.77 per mcf. Any extended weakness in the price of natural gas would have an adverse effect on our operating results and our borrowing capacity because borrowings under our senior credit facility are limited by a borrowing base amount that is established periodically by the lenders. This borrowing base amount is the lenders' estimate of the present value of the future net cash flow from our petroleum and natural gas properties. In addition, under Canadian generally accepted accounting principles, oil and natural gas properties are reviewed for impairment to determine whether the carrying amount of an asset or group of assets may not be recoverable based on expected future cash flows. If we conclude that the carrying amount would not be recoverable, an impairment charge would be included in depreciation, depletion and amortization in our consolidated statement of income, which would adversely affect operating results and shareholders' equity (but as a non-cash charge, it does not affect cash generated from operations). A continuation of recent historically low oil prices or any substantial and extended decline in the prices of oil or natural gas may require us to write down the carrying amount of our oil and natural gas properties. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources". YOU SHOULD NOT UNDULY RELY ON RESERVE INFORMATION BECAUSE RESERVE INFORMATION REPRESENTS ESTIMATES AND OUR ACTUAL RESERVES COULD BE LOWER THAN THE ESTIMATES. Estimates of oil and natural gas reserves involve a great deal of uncertainty, because they depend in large part upon the reliability of available geologic and engineering data, which is inherently imprecise. Geologic and engineering data are used to determine the probability that a reservoir of oil and natural gas exists at a particular location, and whether oil and natural gas are recoverable from a reservoir. The probability of the existence and recoverability of reserves is less than 100% and actual recoveries of proved reserves usually differ from estimates. Estimates of oil and natural gas reserves also require numerous assumptions relating to operating conditions and economic factors, including, among others: o the price at which recovered oil and natural gas can be sold; o the costs associated with recovering oil and natural gas; o the prevailing environmental conditions associated with drilling and production sites; o the availability of enhanced recovery techniques; o the ability to transport oil and natural gas to markets; and o governmental and other regulatory factors, such as taxes and environmental laws. A change in one or more of these factors could result in known quantities of oil and natural gas previously estimated as proved reserves becoming unrecoverable. For example, a decline in the market price of oil or natural gas to an amount that is less than the cost of recovery of such oil and natural gas in a particular location could make production thereof commercially impracticable. Each of these factors, by having an impact on the cost of recovery and the rate of production, will also reduce the present value of future net cash flows from estimated reserves. In addition, estimates of reserves and future net cash flows expected from them are prepared by different independent engineers, or by the same engineers at different times, and may vary substantially. -14- Furthermore, in accordance with Canadian generally accepted accounting principles, we could be required to write down the carrying value of our oil and natural gas properties if oil and natural gas prices become depressed for even a short period of time, or if there are substantial downward revisions to our quantities of proved reserves. A write down would result in a charge to earnings and a reduction of shareholders' equity. IF WE ARE UNABLE TO REPLACE RESERVES THAT WE HAVE PRODUCED, OUR RESERVES, REVENUES AND CASH FLOWS MAY DECLINE. Our future success depends upon our ability to find, develop and acquire additional oil and natural gas reserves that are economically recoverable. Without successful exploration, exploitation or acquisition activities, our reserves, revenues and cash flow may decline. We may not be able to find and develop or acquire additional reserves at an acceptable cost. IF WE ARE UNSUCCESSFUL IN ACQUIRING AND DEVELOPING OIL AND NATURAL GAS PROPERTIES, WE WILL BE PREVENTED FROM INCREASING OUR RESERVES AND OUR BUSINESS WILL BE ADVERSELY AFFECTED BECAUSE WE WILL EVENTUALLY DEPLETE OUR RESERVES. The successful acquisition and development of oil and natural gas properties requires an assessment of: o recoverable reserves; o future oil and natural gas prices and operating costs; o potential environmental and other liabilities; and o productivity of new wells drilled. These assessments are inexact and, if made too inaccurately, we will not recover the purchase price of a property from the sale of production from the property or might not recognize an acceptable return from properties we acquire. In addition, the costs of exploitation and development could materially exceed initial estimates. IF WE ARE UNABLE TO GENERATE SUFFICIENT CASH FLOW OR RAISE CAPITAL, WE WILL NOT BE ABLE TO DEVELOP OUR RESERVES. IF WE ARE UNABLE TO DEVELOP OUR RESERVES, REVENUES AND CASH FLOWS MAY DECLINE. We will be required to make substantial capital expenditures to develop our existing reserves, to discover new oil and natural gas reserves and to make acquisitions. We will be unable to accomplish these tasks if we are unable to generate sufficient cash flow or raise capital in the future. We also make offers to acquire oil and natural gas properties in the ordinary course of our business. If these offers are accepted, our capital needs may increase substantially. DRILLING ACTIVITIES ARE SUBJECT TO MANY RISKS AND ANY INTERRUPTION OR LACK OF SUCCESS IN OUR DRILLING ACTIVITIES WILL ADVERSELY AFFECT OUR BUSINESS. Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered and that we will not recover all or any portion of our investment. The cost of drilling, completing and operating wells is often uncertain. Our drilling operations could be curtailed, delayed or cancelled as a result of numerous factors, many of which are beyond our control, including: o adverse weather conditions; o compliance with governmental requirements; and o shortages or delays in the delivery of equipment and services. OUR OPERATIONS ARE AFFECTED BY OPERATING HAZARDS AND UNINSURED RISKS AND A SHUTDOWN OR SLOWDOWN OF OUR OPERATIONS WILL ADVERSELY AFFECT OUR BUSINESS. There are many operating hazards in exploring for and producing oil and natural gas, including: -15- o our drilling operations could encounter unexpected formations or pressures that could cause damage to equipment or personal injury; o we could experience blowouts, accidents, oil spills, fires or incur other damage to a well that could require us to redrill it or take other corrective action; o we could experience equipment failure that curtails or stops production; o our drilling and production operations, such as trucking of oil, are often interrupted by bad weather; and o we could be unable to access our properties or conduct our operations due to surface conditions. Any of these events could result in damage to, or destruction of, oil and natural gas wells, production facilities or other property. In addition, any of the above events could result in environmental damage or personal injury for which we will be liable. The occurrence of a significant event not fully insured or indemnified against could seriously harm our financial condition and operating results. OUR HEDGING ACTIVITIES COULD RESULT IN LOSSES. The nature of our operations results in exposure to fluctuations in commodity prices. We monitor and, when appropriate, enter into hedging arrangements and physical delivery contracts (in which we agree to sell a fixed amount of oil or natural gas at a set price at a specified date in the future) in order to reduce our exposure to these risks. We are exposed to credit-related losses in the event of non-performance by counter-parties to these financial instruments. From time to time, we enter into hedging activities in an effort to mitigate the potential impact of declines in oil and natural gas prices. If product prices increase above those levels specified in our various hedging agreements, we could lose the cost of floors or a ceiling or fixed price could limit us from receiving the full benefit of commodity price increases. In addition, by entering into these hedging activities, we may suffer financial loss if: o we are unable to produce oil or natural gas to fulfill our obligations; o we are required to pay a margin call on a hedge contract; or o we are required to pay royalties based on a market or reference price that is higher than our fixed or ceiling price. You should also refer to the section of this prospectus entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Hedging Policy". COMPLYING WITH ENVIRONMENTAL AND OTHER GOVERNMENT REGULATIONS COULD BE COSTLY AND COULD NEGATIVELY IMPACT OUR PRODUCTION. Canadian laws and regulations at the provincial and federal level govern the operation and maintenance of our facilities, the discharge of materials into the environment and other environmental protection issues. Under these laws and regulations, we could be liable for personal injury, clean-up costs, remedial measures and other environmental and property damages, as well as administrative, civil and criminal penalties. Although we do carry insurance that covers environmental damages, we are not covered for the full potential liability of environmental damages, so we could be liable or could be required to cease production on properties if environmental damage occurs. It is possible that the costs of complying with environmental laws and regulations in the future will have a material adverse effect on our financial condition or results of operations. Furthermore, future changes in environmental laws and regulations, including adoption of stricter standards or more stringent enforcement, could result in materially increased costs for us, such as larger fines, incurring liability and increased capital expenditures and operating costs, any of which could have -16- a material adverse effect on our financial condition or results of operations. You should refer to the section of this prospectus entitled "Business -- Environmental". FACTORS BEYOND OUR CONTROL AFFECT OUR ABILITY TO MARKET PRODUCTION. SINCE WE CANNOT PROTECT OURSELVES FROM THESE FACTORS, THE IMPACT OF THEM, IF SERIOUS, WILL ADVERSELY AFFECT OUR BUSINESS. Our ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could: o limit the availability of natural gas processing capacity which would limit the amount of natural we produce; o limit the availability of pipeline capacity which could limit the amount of natural gas that we can market; o limit the supply of and reduce demand for oil and natural gas which could reduce our revenues; o increase the availability of alternative fuel sources which could reduce demand for oil and natural gas thereby reducing our revenues; In addition: o the effects of inclement weather; o Canadian federal and provincial regulation of oil and natural gas marketing; and o Canadian federal regulation of natural gas sold or transported outside of the province of Alberta could adversely effect our ability to economically produce and market oil or natural gas at current levels of production. OUR ACCESS TO FIXED COSTS PROCESSING AND TRANSPORTATION CAPACITY COULD BE TERMINATED, RESULTING IN HIGHER COSTS. The agreement governing the sale of the Mazeppa gas plants and related facilities, which provides us with access to processing and transportation capacity at set rates in our key southern Alberta core area, contains provisions stating that our counter-party can terminate the agreement if the expenses of operating the gas plants exceed the revenues of the gas plant for a period of 12 consecutive months. If the contract is terminated, our business would be adversely affected, as we would be forced to pay either higher rates for gas processing and transportation at the Mazeppa gas plant or find new processing and transportation facilities. ESSENTIAL EQUIPMENT MIGHT NOT BE AVAILABLE, WHICH COULD INTERFERE WITH THE OPERATION OF OUR BUSINESS. Oil and natural gas exploration and development activities depend upon the availability of drilling and related equipment in the particular areas where those activities will be conducted. Demand for that equipment or access restrictions may affect the availability of that equipment to us and delay our exploration and development activities. WE ARE A MEDIUM-SIZED COMPANY OPERATING IN A HIGHLY COMPETITIVE INDUSTRY AND LARGER COMPANIES WITH GREATER RESOURCES CAN OUTBID US FOR ACQUISITIONS. The oil and natural gas industry is highly competitive. Our competitors include companies that have greater financial and personnel resources than we do. Our ability to acquire additional properties and to discover reserves in the future depends upon our ability to evaluate and select suitable properties and to complete transactions in a highly competitive and challenging environment. You should refer to the section of this prospectus entitled "Business -- Competition". -17- RISKS RELATING TO THE EXCHANGE NOTES AND THE EXCHANGE OFFER OUR SUBSTANTIAL INDEBTEDNESS COULD ADVERSELY AFFECT OUR FINANCIAL HEALTH AND PREVENT US FROM FULFILLING OUR OBLIGATIONS UNDER THE EXCHANGE NOTES. We have a significant amount of indebtedness. As of June 30, 2002, we had total indebtedness of $251.0 million, which consists of the initial notes and approximately $394,000 of indebtedness under capital lease obligations. In addition, after giving pro forma effect to the offering of the initial notes and the application of the net proceeds of that offering, our ratio of earnings to fixed charges would have been 3.3x, for the year ended December 31, 2001. Our substantial indebtedness could have important consequences to you. For example, it could: o make it more difficult for us to satisfy our obligations with respect to the exchange notes; o increase our vulnerability to general adverse economic and industry conditions; o require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, research and development efforts and other general corporate purposes; o limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; o place us at a competitive disadvantage compared to our competitors that have less debt; and o limit our ability to borrow additional funds. In addition, the indenture and our senior credit facilities contain financial and other restrictive covenants that will limit our ability to engage in activities that may be in our long-term best interests. Our failure to comply with those covenants could result in an event of default which, if not cured or waived, could result in the acceleration of all of our debt. DESPITE OUR CURRENT LEVEL OF INDEBTEDNESS, WE AND OUR SUBSIDIARIES MAY STILL BE ABLE TO INCUR SUBSTANTIALLY MORE DEBT. THIS COULD FURTHER EXACERBATE THE RISKS ASSOCIATED WITH OUR SUBSTANTIAL LEVERAGE. We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the indenture do not fully prohibit us or our subsidiaries from doing so. Our senior credit facilities currently permit additional borrowing of up to $168.0 million. All of those borrowings would rank senior to the exchange notes and our subsidiaries' guarantees. If new debt is added to our and our subsidiaries' current level of indebtedness, the related risks that we and they now face could intensify. See "Description of Other Indebtedness". TO SERVICE OUR INDEBTEDNESS, WE WILL REQUIRE A SIGNIFICANT AMOUNT OF CASH. OUR ABILITY TO GENERATE CASH DEPENDS ON MANY FACTORS BEYOND OUR CONTROL. Our ability to make payments on and to refinance our indebtedness, including these notes, and to fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our senior credit facilities in an amount sufficient to enable us to pay our indebtedness, including these notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including these exchange notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our senior credit facilities and these exchange notes, on commercially reasonable terms or at all. -18- THE EXCHANGE NOTES ARE EFFECTIVELY SUBORDINATED TO OUR SECURED INDEBTEDNESS AND CERTAIN INDEBTEDNESS OF OUR SUBSIDIARIES. The exchange notes will be unsecured and therefore are effectively subordinated to any of our and our subsidiaries secured indebtedness to the extent of the value of the assets securing such indebtedness. Up to $168.0 million is available for borrowing as additional senior debt under our senior credit facilities. The indenture permits us to incur additional secured indebtedness provided certain conditions are met. See "Description of the Exchange Notes -- Certain Covenants -- Incurrence of Indebtedness and Issuance of Preferred Stock". Consequently, in the event we are the subject of a bankruptcy, liquidation, dissolution, reorganization or similar proceeding, the holders of any secured indebtedness will be entitled to proceed against the collateral that secures the secured indebtedness, and the collateral may not be available to repay debts owed to our unsecured creditors, including holders of the notes. As a result, holders of the notes may not be repaid the principal of and interest on the notes that they are owed. The indenture also permits our subsidiaries to incur indebtedness under our senior credit facilities which would be secured by the assets of such subsidiaries. The exchange notes will be effectively subordinated to such subsidiary indebtedness. WE MAY NOT HAVE THE ABILITY TO RAISE THE FUNDS NECESSARY TO FINANCE THE CHANGE OF CONTROL OFFER REQUIRED BY THE INDENTURE. Upon the occurrence of specified change of control events, we will be required to offer to repurchase all outstanding exchange notes at 101% of the principal amount thereof plus accrued and unpaid interest and additional interest, if any, to the date of repurchase. The change of control events include a sale of all or substantially all of the our assets, the approval by our directors or our shareholders of a plan relating to the dissolution of our company, a transaction which places the ownership of a majority of our company within one person, and a transaction which causes a majority of our directors to cease being the directors of our company. However, it is possible that we will not have sufficient funds at the time of the change of control to make the required repurchase of exchange notes or that restrictions in our senior credit facilities will not allow such repurchases. If we are unable to make the required repurchases, we will be in default and the holders of notes will be allowed to take certain actions against us, including in certain circumstances accelerating our repayment of the principle of and any accrued but unpaid interest on the notes. See "Description of the Exchange Notes -- Repurchase at the Option of Holders". FEDERAL AND STATE STATUTES ALLOW COURTS, UNDER SPECIFIC CIRCUMSTANCES, TO VOID GUARANTEES AND REQUIRE NOTE HOLDERS TO RETURN PAYMENTS RECEIVED FROM GUARANTORS. Under U.S. and Canadian federal bankruptcy laws and comparable provisions of state and provincial fraudulent transfer laws, a guarantee could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee: o incurred the debt with the intent to hinder, delay or defraud creditors; o received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee; and o was insolvent or rendered insolvent by reason of such incurrence; or o was engaged in a business or transaction for which the guarantor's remaining assets constituted unreasonably small capital; or o intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature. In addition, any payment by that guarantor pursuant to its guarantee could be voided and required to be returned to the guarantor or to a fund for the benefit of the creditors of the guarantor. YOU MIGHT HAVE DIFFICULTY ENFORCING CIVIL LIABILITIES AGAINST US IN THE UNITED STATES. We are a corporation organized under the laws of Alberta, Canada. All of our directors and officers and some of the experts named in this prospectus reside principally in Canada. Because these persons are located outside the United States it may not be possible for you to effect service of process within the United States upon those persons. Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in U.S. courts, because all or a -19- substantial portion of our assets and the assets of these persons are located outside the United States. We have been advised by Fraser Milner Casgrain LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the U.S. federal securities laws and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors and officers or the experts named in this prospectus. THE ISSUANCE OF THE EXCHANGE NOTES MAY ADVERSELY AFFECT THE MARKET FOR THE INITIAL NOTES. If initial notes are tendered for exchange and accepted in the exchange offer, the trading market for the untendered and tendered but unaccepted initial notes could be adversely affected. See "The Exchange Offer" and the "Risk Factors -- Your failure to participate in the exchange offer will have adverse consequences". YOUR FAILURE TO PARTICIPATE IN THE EXCHANGE OFFER WILL HAVE ADVERSE CONSEQUENCES. The initial notes were not registered under the Securities Act or under the securities laws of any state and you may not resell them, offer them for resale or otherwise transfer them unless they are subsequently registered or resold under an exemption from the registration requirements of the Securities Act and applicable state securities laws. If you do not exchange your initial notes for exchange notes pursuant to this exchange offer, or if you do not properly tender your initial notes in this exchange offer, you will not be able to resell, offer to resell or otherwise transfer the initial notes unless they are registered under the Securities Act or unless you resell them, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act. In addition, you may no longer be able to obligate us to register the initial notes under the Securities Act. SOME PERSONS WHO PARTICIPATE IN THE EXCHANGE OFFER MUST DELIVER A PROSPECTUS IN CONNECTION WITH RESALES OF THE EXCHANGE NOTES. In some instances described in this prospectus under "Plan of Distribution", you will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer your exchange notes. In these cases, if you transfer any exchange note without delivering a prospectus meeting the requirements of the Securities Act or without an exemption from registration of your exchange notes under the Securities Act, you may incur liability under the Securities Act. We do not and will not assume, or indemnify you against, this liability. ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS We are a corporation organized under the laws of Alberta. All of our directors and officers and some of the experts named in this prospectus reside principally in Canada. Because these persons are located outside the United States, it may not be possible for you to effect service of process within the United States upon those persons. Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in U.S. courts, because all or a substantial portion of our assets and the assets of these persons are located outside the United States. We have been advised by Fraser Milner Casgrain LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the U.S. federal securities laws and as to the enforceability in Canadian courts of judgments of U.S. courts obtained in actions based upon the civil liability provisions of the U.S. federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors and officers or the experts named in this prospectus. CURRENCY TRANSLATION UNLESS OTHERWISE INDICATED, ALL REFERENCES TO "$" IN THIS PROSPECTUS REFER TO CANADIAN DOLLARS AND ALL REFERENCES TO "US$" REFER TO UNITED STATES DOLLARS. -20- The following table lists, for each period presented, the high and low exchange rates, the average of the exchange rates on the last day of each month during the period indicated and the exchange rates at the end of the period for one Canadian dollar, expressed in United States dollars, based on the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York. On September 19, 2002, the inverse of the noon buying rate in New York City for cable transfers of Canadian dollars was Cdn$1.00 = US$O.6358.
YEAR ENDED DECEMBER 31, --------------------------------------------------------------- 1997 1998 1999 2000 2001 ---------- --------- ---------- ---------- ---------- High for the period...... 0.7487 0.7105 0.6925 0.6969 0.6697 Low for the period....... 0.6945 0.6341 0.6535 0.6410 0.6244 End of period............ 0.6999 0.6504 0.6925 0.6669 0.6279 Average for the period... 0.7198 0.6714 0.6740 0.6725 0.6444
FORWARD-LOOKING STATEMENTS This prospectus contains forward-looking statements within the meaning of the U.S. federal securities laws. These statements are subject to certain risks and uncertainties and may be based on assumptions that could cause actual results to differ materially from those included in the forward-looking statements. The words "believe", "expect", "intend", "estimate", "anticipate" and similar expressions, as well as future or conditional verbs such as "will", "should", "would" and "could" often identify forward-looking statements. With respect to forward-looking statements contained in this prospectus, we have made assumptions regarding, among other things: o future crude oil and natural gas prices; o the cost of expanding our property holdings; o our ability to obtain equipment in a timely manner to meet our demand; o our ability to market crude oil and natural gas successfully to current and new customers; o the impact of increasing competition; and o our ability to obtain financing on acceptable terms. The information contained in this prospectus, including the information provided under the heading "Risk Factors", identifies factors that could affect our operating results and performance. We urge you to carefully consider those factors. Our forward-looking statements are expressly qualified in their entirety by this cautionary statement. Our forward-looking statements are only made as of the date of this prospectus and we undertake no obligation to publicly update these forward-looking statements to reflect new information, subsequent events or otherwise unless such new information causes such statements to become materially different or misleading. USE OF PROCEEDS We will not receive any cash proceeds from the issuance of the exchange notes in exchange for the outstanding initial notes. We are making this exchange solely to satisfy our obligations under the registration rights agreement entered into in connection with the offering of the initial notes. In consideration for issuing the exchange notes, we will receive initial notes in the same aggregate principal amount. -21- The net proceeds to us from the offering of the initial notes were US$156.3 million ($245.5 million based upon the noon buying rate on May 8, 2002 of US$1.00 = $1.5708), after deducting the initial purchaser's discount and offering expenses. We used the proceeds from the offering to repay off our outstanding debt under our senior credit facilities, which was $236.5 million at the close of the offering of initial notes. The remaining net proceeds of approximately US$5.7 million were used for general corporate purposes. Our senior credit facilities bear interest at our lender's prime rate or at the banker's acceptance rate or the London Interbank Offered Rate (referred to as LIBOR) plus a margin based on our ratio of total consolidated debt to cash flow that was set at the close of the offering of initial notes at 0.125%, 1.125% and 1.125%, respectively. The senior credit facilities mature on July 9, 2003. CAPITALIZATION The following table sets forth our actual capitalization as of June 30, 2002. You should read this table together with "Management's Discussion and Analysis of Financial Condition and Results of Operations", "Selected Historical Consolidated Financial Data" and the financial information beginning on page F-1. The initial notes have been converted to Canadian dollars at the noon buying rate on June 28, 2002, which was US$1.00 = $1.5187. AS OF JUNE 30, 2002 --------------- (DOLLARS IN THOUSANDS) Cash and cash equivalents............ $ 640 =============== Long-term debt: Senior credit facilities(1)...... $ - Capital lease obligations 394 Notes offered.................... 250,586 --------------- Total long-term debt.......... 250,980 Shareholders' equity................. 233,170 --------------- Total capitalization $ 484,150 =============== ----------- (1) Prior to the offering of the initial notes, our senior credit facilities provided for total borrowings of up to $240.0 million. Upon the completion of the offering of initial notes, we repaid substantially all amounts outstanding under our senior credit facilities, the size of the facilities was reduced and approximately $168.0 million is currently available for borrowings under such facilities, subject to the conditions contained therein. You should refer to the section of this prospectus entitled "Description of Other Indebtedness -- Senior Credit Facilities". -22- SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA The following table provides our selected financial data for the five years ended December 31, 2001 and for the six-month periods ended June 30, 2001 and 2002. The financial data for each of the years in the five-year period ended December 31, 2001 have been derived from our audited consolidated financial statements for those periods, which were audited by Grant Thornton LLP, independent accountants. The financial data for the six-month periods ended June 30, 2001 and 2002 have been derived from our unaudited consolidated financial statements for those periods. The unaudited financial statements have been prepared on the same basis as our audited financial statements. We believe that the information presented in our unaudited financial statements contain all adjustments necessary for a fair presentation of the financial information presented (consisting only of normal recurring adjustments). The historical data for the interim period is not necessarily indicative of the results that may be expected for our full year of operations. You should read our audited financial statements and the related notes included elsewhere in this prospectus. In some respects, Canadian generally accepted accounting principles differ from United States generally accepted accounting principles. For a discussion of the principal differences between Canadian and United States generally accepted accounting principles, you should read Note 17 to our consolidated financial statements included in this prospectus.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30, ------------------------------------------------------------- --------------------- 1997 1998 1999 2000 2001 2001 2002 --------- --------- --------- ---------- --------- --------- -------- (Dollars in thousands, except ratios) (unaudited) CANADIAN GAAP STATEMENT OF EARNINGS: Revenue: Oil and natural gas revenues $ 17,674 $ 30,545 $ 97,016 $ 213,376 $ 244,970 $ 153,612 $ 96,566 Royalties, net of Alberta Royalty Tax Credits...... (2,453) (2,790) (16,105) (44,695) (55,919) (36,072) (21,142) ---------- ---------- ---------- ---------- --------- --------- ---------- Net revenue.............. 15,221 27,755 80,911 168,681 189,051 117,540 75,424 ---------- ---------- ---------- ---------- --------- --------- ---------- Expenses: Operating.................. 3,787 7,476 20,521 31,571 40,222 18,508 21,855 General and administrative. 903 1,517 4,222 5,915 6,302 3,692 4,316 Interest................... 270 1,023 6,939 12,772 12,863 6,284 6,560 Unrealized foreign exchange gain -- -- -- -- -- -- (8,465) Depletion and depreciation. 3,896 6,671 20,160 41,767 50,450 23,789 26,427 ---------- ---------- ---------- ---------- --------- --------- ---------- Total expenses........... 8,856 16,687 51,842 92,025 109,837 52,273 50,693 ---------- ---------- ---------- ---------- --------- --------- ---------- Earnings before income taxes 6,365 11,068 29,069 76,656 79,214 65,267 24,731 Income taxes............... 2,639 4,464 11,981 36,597 23,578 17,772 10,233 ---------- ---------- ---------- ---------- --------- --------- ---------- Net earnings............... $ 3,726 $ 6,604 $ 17,088 $ 40,059 $ 55,636 $ 47,495 $ 14,498 ========== ========== ========== ========== ========= ========= ========= CASH FLOW DATA: Cash provided (used) by: Operating activities........... $ 8,426 $ 12,378 $ 37,829 $ 104,187 $ 121,068 $ 92,449 $ 51,102 Investing activities........... (90,818) (77,682) (111,033) (119,069) (176,066) (78,237) (69,654) Financing activities........... 80,546 65,304 58,144 29,942 60,050 (12,870) 14,140 OTHER FINANCIAL DATA: EBITDA(1)...................... $ 10,530 $ 18,762 $ 56,168 $ 131,195 $ 142,527 $ 95,340 $ 57,718 Ratio of EBITDA to interest expense 39.0x 18.3x 8.1x 10.3x 11.1x 15.2x 8.8x Ratio of earnings to fixed charges(2)................. 24.6x 11.8x 5.2x 7.0x 7.2x 11.4x 4.8x BALANCE SHEET DATA: Total assets................... $ 122,176 $ 212,083 $ 349,367 $ 524,272 $ 693,973 $ 569,815 $ 717,496 Long-term debt................. 41,769 93,616 159,714 183,376 230,000 182,000 250,586 Shareholders' equity........... 67,026 81,267 116,702 157,796 217,860 197,169 233,170 U.S. GAAP Total Assets................... $ 124,188 $ 268,262 $ 416,271 $ 522,913 $ 692,591 $ 568,211 $ 717,710 Net earnings................... 3,668 2,033 7,345 32,881 46,921 47,495 14,498 EBITDA(1)...................... 10,519 18,688 54,702 126,711 142,527 95,340 57,718 Ratio of EBITDA to interest expense 39.0x 18.3x 7.9x 9.9x 11.1x 15.2x 8.8x Ratio of earnings to fixed charges(2)................. 24.2x 11.1x 3.9x 6.7x 7.2x 11.4x 4.8x
---------- (1) EBITDA is calculated as earnings before extraordinary items, excluding interest expense and other debt expenses, income tax, depletion, depreciation and amortization. EBITDA is not a measure of cash flow as determined by Canadian or United States generally accepted accounting principles. Certain items excluded from EBITDA are significant components in understanding and assessing a company's financial performance, such as a -23- company's cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of EBITDA. We have included information concerning EBITDA because EBITDA is a measure used by certain investors in determining a company's historical ability to service its indebtedness. However, viewing EBITDA as an indicator of our ability to service indebtedness should be done with caution, as we might be required to conserve funds or to allocate funds to business or legal purposes other than servicing our indebtedness. EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flow as determined in accordance with Canadian or United States generally accepted accounting principles or as an indicator of our operating performance or liquidity. EBITDA is not necessarily comparable to a similarly titled measure of another company. (2) For purposes of computing the ratio of earnings to fixed charges, earnings consist of earnings before income taxes and fixed charges. Fixed charges consist of interest and amortization of debt issuance costs. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS YOU SHOULD READ THE FOLLOWING DISCUSSION AND ANALYSIS ALONG WITH OUR AUDITED AND UNAUDITED FINANCIAL STATEMENTS AND THE RELATED NOTES APPEARING ELSEWHERE IN THIS PROSPECTUS. THIS DISCUSSION AND ANALYSIS CONTAINS FORWARD-LOOKING STATEMENTS THAT INVOLVE RISKS AND UNCERTAINTIES. APPLICATION OF CRITICAL ACCOUNTING POLICIES Our consolidated financial statements have been prepared in accordance with the accounting principles generally accepted in Canada which, in most respects, conform to accounting principles generally accepted in the United States of America. The significant difference in these principles, as they apply to our statement of earnings, balance sheets and statements of cash flow are detailed in Note 17 of our consolidated financial statements attached hereto. The application of generally accepted accounting principles involves certain assumptions, judgements and estimates that affect reported amounts of assets, liabilities, revenues and expenses. The basis for these estimates is historical experience and various other assumptions that we believe to be reasonable. These estimates are the basis for making judgements about the carrying value of assets and liabilities. Actual results could differ from these estimates under different assumptions or conditions. Thus, the application of these principles can produce varying results from company to company. We follow the full cost method of accounting for our petroleum and natural gas operations. Under this accounting method, all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Capitalized costs, as well as the estimated future expenditures to develop proved reserves, are depleted using the unit-of-production method based on estimated proved oil and gas reserves. In applying the full cost method, we calculate a ceiling test whereby the carrying value of petroleum and natural gas properties and production equipment, net of recorded future income taxes and the accumulated provision for site restoration and abandonment costs, is compared annually to an estimate of future net cash flow from the production of proved reserves. Net cash flow is estimated using year end prices, less estimated future general and administrative expenses, financing costs and income taxes. Should this comparison indicate an excess carrying value, the excess is charged against earnings as additional depletion and depreciation. For further details on our accounting policies and discussion of new accounting pronouncements, see Notes 2, 3 and 17 of the Notes to our Consolidated Financial Statements beginning on page F-6. OVERVIEW We are an independent public company actively engaged in the exploration, development and production of natural gas, natural gas liquids and crude oil in Western Canada. Our activities are concentrated in four core geographic areas in Alberta. We have obtained our reserves through a combination of strategic acquisitions and exploration and development activities. We commenced operations in July 1993. Since 1997, we have acquired three oil and natural gas companies: J.M. Huber Canada Limited in December 1998 for $91.4 million, Coparex Canada Ltd. in December 1999 for $74.6 million and Hornet Energy Ltd. in July 2001 for $42.0 million. -24- We have established our current operating base through a combination of a program of full-cycle exploration and strategic acquisitions. This involves: o establishing core geographic operating areas through strategic acquisitions; o developing significant operational and technical expertise through exploration and development activities; o acquiring strategic control over infrastructure; and o reinvesting operating cash-flow to further consolidate our position in each of our core areas and to further grow our inventory of drilling prospects. As of June 30, 2002, we held working interests in 826,591 (635,371 net) acres of undeveloped land and we held working interests in 1,056 gross (437.2 net) producing wells in western Canada. Historically, the majority of our proved reserves and production has been natural gas, with crude oil and natural gas liquids comprising a smaller portion of our total production. A summary of our production and net revenue is provided in the table below.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------------ ----------------------- 1999 2000 2001 2001 2002 ---------- ---------- ---------- ---------- ---------- PRODUCTION: Natural gas (mmcf/d)........................... 54.3 68.4 77.8 73.6 85.5 Natural gas liquids (bbls/d)................... 1,268 1,443 1,386 1,186 1,622 Crude oil (bbls/d)............................. 2,303 3,374 3,617 3,562 3,327 NET REVENUE: Natural gas (thousands of dollars)............. $ 52,008 $ 113,649 $ 135,547 $ 89,110 $ 50,490 Crude oil and natural gas liquids(thousands of dollars)....................................... 28,903 55,032 53,504 28,430 24,934 ---------- --------- --------- --------- -------- $ 80,911 $ 168,681 $ 189,051 $ 117,540 $ 75,424 ========== ========= ========= ========= ========
A summary of our proved reserves as at certain dates is provided in the table below: YEAR ENDED DECEMBER 31, ------------------------------------ 1999 2000 2001 --------- --------- --------- PROVED RESERVES: Natural gas (mmcf)...................... 181,759 223,761 262,448 Crude oil and natural gas liquids (mbbls)...................... 10,682 9,423 9,777 Natural gas equivalent (mmcfe).......... 245,851 280,302 321,110 Over the past three fiscal years, our financial performance and the period to period comparability of our performance has been affected by: o production growth of 42% from 1999 to 2001; o the acquisitions of J.M. Huber, Coparex and Hornet; o borrowing to fund our growth; and o crude oil, natural gas liquids and natural gas sales price volatility. Of these factors, the volatility of commodity prices, particularly natural gas prices, has had the most significant impact on our financial performance. The following tables sets forth the average prices realized by us, net of royalties, both before and after hedging, on sales of natural gas, crude oil and natural gas liquids for the periods indicated: -25-
SIX MONTHS ENDED PRICES BEFORE HEDGING: YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------------------- ------------------------------------ ----------------------- 1999 2000 2001 2001 2002 ------ ------ ------- ------- -------- Natural gas ($/mcf).................... 2.62 4.54 4.64 6.61 3.25 Natural gas liquids ($/bbl)............ 26.69 40.02 32.55 36.45 32.37 Crude oil ($/bbl)...................... 16.27 25.12 20.80 22.95 18.38 SIX MONTHS ENDED PRICES AFTER HEDGING: YEAR ENDED DECEMBER 31, JUNE 30, ---------------------------------------- ------------------------------------ ----------------------- 1999 2000 2001 2001 2002 ------ ------ ------- ------- -------- Natural gas ($/mcf).................... 2.62 4.54 4.77 6.69 3.26 Natural gas liquids ($/bbl)............ 16.27 25.12 20.80 22.95 18.38 Crude oil ($/bbl)...................... 25.43 33.82 32.55 36.45 32.44
From time-to-time, we enter into hedge transactions to manage fluctuations in commodity prices. Currently, we have fixed the price on approximately 22% of our current 2002 production. Additionally, our financial policy is such that when necessary, commodity hedging contracts are utilized to support the economics of both corporate and property acquisitions. Oil and gas revenues for 2001 included gains of $3.7 million (2000 - loss of $7.7 million) on such transactions. Finding and development costs are the costs of adding proved reserves and include the costs of undeveloped land, seismic, drilling, completion, tie-in and construction of field facilities as well as costs of acquiring proved reserves. Our average finding and development costs on a proved reserve basis were $10.60 per boe in fiscal 1999, $10.17 per boe in fiscal 2000 and $14.25 per boe in fiscal 2001. Finding and development costs increased in fiscal 2001 due to the acquisition of Hornet combined with increased expenditures relating to land and seismic. The purchase price of the Hornet acquisition was approximately $29.1 million in cash plus the assumption of $10.9 million in debt, a working capital deficiency of $1.5 million and transaction costs of $0.5 million. We funded the cash portion of the Hornet acquisition out of working capital. Finding and development costs increased in fiscal 1999 primarily as a result of the acquisition of Coparex. Additionally, finding and development costs in fiscal 1999 were impacted by our joint venture arrangements in our southern Alberta area, where we earned a 50% interest in 3,200 to 3,840 acres of joint venture lands by incurring 100% of costs to the casing point. The increase in fiscal 2000 was partially attributable to higher field costs which was a result of the increased level of industry activity, but was mainly due to our capital program in fiscal 2000, which was skewed proportionately higher to upfront capital intensive activities, such as land, seismic and facilities spending. Our three-year average finding and development costs to December 31, 2001 were $11.75 per boe. Our five-year average finding and development costs to December 31, 2001 were $9.25 per boe. Our netback, which is our gross revenue less royalties, operating costs and general and administrative expenses, is expressed as the netback per boe.
SIX MONTHS ENDED YEAR ENDED DECEMBER 31, JUNE 30, ------------------------------------- ---------------------- 1999 2000 2001 2001 2002 -------- ---------- ---------- ---------- ---------- Revenue.................................... $ 21.05 $ 35.95 $ 37.34 $ 49.90 $ 27.80 Royalties, net ARTC........................ (3.49) (7.53) (8.52) (11.72) (6.09) -------- ---------- ---------- ---------- ---------- Net revenue............................ 17.56 28.42 28.82 38.18 21.71 Operating costs............................ (4.45) (5.32) (6.13) (6.01) (6.29) General and administrative expenses........ (0.92) (1.00) (0.96) (1.20) (1.24) -------- ---------- ---------- ---------- ---------- Netback................................ $ 12.19 $ 22.10 $ 21.73 $ 30.97 $ 14.18 ======== ========== ========== ========== ==========
SIX MONTHS ENDED JUNE 30, 2002 COMPARED TO SIX MONTHS ENDED JUNE 30, 2001. PRODUCTION. For the first six months of fiscal 2002, our natural gas production averaged 85.5 mmcf/d, an increase of 16% from the same period in fiscal 2001. For the first six months of fiscal 2002, our natural gas liquids production increased by 37% to 1,622 bbls/d from 1,186 bbls/d for the same period in fiscal 2001. For the first six months of 2002, our crude oil production averaged 3,327 bbls/d, a 7% decrease from 3,562 bbls/d for the same period in fiscal 2001. On a barrel of oil equivalent basis, production for the first six months of fiscal 2002 averaged 19,193 boe/d, a 13% increase as compared with 17,009 boe/d for the same period in fiscal 2001. Natural gas represented 74% of our production mix during the first six months of fiscal 2002. Our average natural gas price of $3.26 per mcf for the first six months of fiscal 2002 represented a 51% decrease over the same period in fiscal 2001. Our average crude oil price of $32.44 per barrel in the first six months of fiscal 2002 -26- represented a 11% decrease over the same period in fiscal 2001. Our average natural gas liquids price was $18.38 per barrel for the first six months of fiscal 2002 represented a 20% decrease over the same period in fiscal 2001. The AECO spot price averaged $3.68 per GJ for the first six months of fiscal 2002 compared to $8.52 per GJ for the same period in fiscal 2001. REVENUE. For the first six months of fiscal 2002, our gross revenue decreased by 37% to $96.6 million, as compared to $153.6 million during the first six months of fiscal 2001. This decrease was attributable to substantially lower commodity prices in fiscal 2002. The West Texas Intermediate oil benchmark price and the AECO natural gas price index both decreased substantially from the first six months of fiscal 2001, down 16% and 57%, respectively, which was offset marginally by higher production volumes. The 10% increase in gross production volumes contributed approximately $8.6 million to the change in gross revenue. The 43% decrease in average commodity prices affected approximately $65.6 million of the decrease in gross revenue. ROYALTIES. As a result of lower commodity prices in the first six months of fiscal 2002, our royalty commitments, after royalty credits, decreased to $21.1 million from $36.1 million during the same period in fiscal 2001. Our average royalty rate on production was 21.9% for the first six months of fiscal 2002, as compared to 23.5% for the first six months of fiscal 2001. OPERATING COSTS. Our operating costs increased to $21.9 million in the first six months of fiscal 2002 from $18.5 million in the same period in fiscal 2001. This increase was primarily due to higher production levels. For the first six months of fiscal 2002, operating costs were $6.29 per boe, a 5% increase over the operating costs of $6.01 per boe for the same period in fiscal 2001. GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses increased to $4.3 million for the first six months of fiscal 2002, from $3.7 million for the same period in fiscal 2001. On a barrel of oil equivalent basis, general and administrative expenses were $1.24 for the first six months of fiscal 2002, an increase of 3% from $1.20 during the same period in fiscal 2001. INTEREST EXPENSE. For the first six months of 2002, our interest expense increased to $6.6 million from $6.3 million during the same period in fiscal 2001. This marginal increase reflects higher debt servicing costs associated with our initial notes. DEPLETION AND DEPRECIATION. Our depletion and depreciation expenses, which include a provision for the future costs of abandonment and restoration, were $26.4 million for the first six months of fiscal 2002, an 11% increase over the $23.8 million in the same period in fiscal 2001. On a barrel of oil equivalent basis, depletion and depreciation costs were $7.61 per boe for the first six months of fiscal 2002, as compared to $7.73 per boe for the same period in fiscal 2001. INCOME TAXES. Our tax expense of $0.9 million for the first six months of 2002 consisted of a Large Corporation Tax, as compared to $0.5 million Large Corporation Tax expense for the same period in 2001. Future income taxes for the first six months of 2002 were $9.3 million, a decrease of 46% for the same period in 2001. NET EARNINGS. For all of the reasons specified above, net earnings for the first six months of fiscal 2002 decreased by 69% to $14.5 million from $47.5 million realized in the same period last year. YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000. PRODUCTION. For fiscal 2001, our natural gas production averaged 77.8 mmcf/d, an increase of 14% from fiscal 2000. For fiscal 2001, our natural gas liquids production decreased by 4% to 1,386 bbls/d from 1,443 bbls/d for fiscal 2000. For fiscal 2001, our crude oil production averaged 3,617 bbls/d, a 7% increase from 3,374 bbls/d for fiscal 2000. On a barrel of oil equivalent basis, production for fiscal 2001 averaged 17,974 boe/d, an 11% increase as compared with 16,219 boe/d for fiscal 2000. Natural gas represented 72% of our production mix during fiscal 2001. Our average natural gas price of $4.77 per mcf for fiscal 2001 represented a 5% increase over fiscal 2000. Our average crude oil price of $32.55 per barrel in fiscal 2001 represented a 4% decrease over fiscal 2000. Our average natural gas liquids price was $20.80 per barrel for fiscal 2001 represented an 17% decrease over fiscal 2000. The AECO spot price averaged $5.97 per GJ for fiscal 2001 compared to $5.55 per GJ for fiscal 2000. -27- REVENUE. For fiscal 2001, our gross revenue increased by 15% to $245.0 million, as compared to $213.4 million during fiscal 2000. This increase was attributable to higher production volumes, stronger commodity prices and the acquisition of Hornet Energy Ltd. The 14% increase in gross production volumes contributed approximately $29.6 million of the incremental gross revenue. The 4% increase in average commodity prices contributed approximately $2.0 million of the increase in gross revenue. ROYALTIES. As a result of strong commodity prices and higher production volumes in fiscal 2001, our royalty commitments, after royalty credits, increased to $55.9 million from $44.7 million during fiscal 2000. Our average royalty rate on production was 22.8% for fiscal 2001, as compared to 20.9% for fiscal 2000. OPERATING COSTS. Our operating costs increased to $40.2 million in fiscal 2001 from $31.6 million in fiscal 2000. This increase was attributable to higher production levels, a significant increase in our energy costs and increases in the costs of goods and services associated with high levels of upstream activity in our industry. For fiscal 2001, operating costs were $6.13 per boe, a 15% increase over the operating costs of $5.32 per boe for fiscal 2000. GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses increased to $6.3 million for fiscal 2001, from $5.9 million for fiscal 2000. The increase was attributable to the higher level of staffing necessitated by our increased level of activity. These expenses represented 2.6% of gross revenues. On a barrel of oil equivalent basis, general and administrative costs were $0.96 for 2001, a decrease of 4% from $1.00 during fiscal 2000. INTEREST EXPENSE. For fiscal 2001, our interest expense was $12.9 million, which is consistent with the $12.8 million during fiscal 2000. A lower average cost of borrowing in 2001 was offset by higher bank debt balances for the year. DEPLETION AND DEPRECIATION. Our depletion and depreciation expenses, which include a provision for the future costs of abandonment and restoration, were $50.5 million for fiscal 2001, an increase of 21% from $41.8 million in fiscal 2000. This increase resulted from higher production levels and increased finding and development costs for new reserves additions. On a barrel of oil equivalent basis, depletion and depreciation costs were $7.69 per boe for fiscal 2001, as compared to $7.04 per boe for fiscal 2000. INCOME TAXES. Our tax expense of $1.3 million for 2001 consisted of a Large Corporation Tax and was 44% higher than the $0.9 million for fiscal 2000. Future income taxes for fiscal 2001 were $22.2 million, an decrease of 38% from fiscal 2000. Effective April 1, 2001, the Alberta government decreased the provincial income tax rate from 15.5% to 13.5%. This decrease had the immediate effect of reducing our previously recorded future income tax liability, resulting in a recovery of future income taxes which has been recognized in the second quarter of fiscal 2001. NET EARNINGS. For all of the reasons specified above, net earnings for fiscal 2001 increased by 39% to $55.6 million from $40.1 million realized in fiscal 2000. YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 PRODUCTION. For fiscal 2000, our natural gas production averaged 68.4 mmcf/d, an increase of 26% from fiscal 1999. For fiscal 2000, our natural gas liquids production increased by 14% to 1,443 bbls/d from 1,268 bbls/d during fiscal 1999. For fiscal 2000, our crude oil production averaged 3,374 bbls/d, a 47% increase from 2,303 bbls/d for fiscal 1999. On a barrel of oil equivalent basis, production for fiscal 2000 averaged 16,219 boe/d, a 28% increase as compared with 12,627 boe/d for fiscal 1999. Natural gas represented 70% of our production mix during fiscal 2000. Our average natural gas price of $4.54 per mcf for fiscal 2000 represented a 73% increase over the same period in fiscal 1999. Our average crude oil price of $33.82 per barrel in fiscal 2000 represented a 33% increase over the same period in fiscal 1999. Our average natural gas liquids price of $25.12 per barrel for fiscal 2000 represented a 54% increase over the same period in fiscal 1999. The AECO spot price averaged $5.55 per GJ during fiscal 2000 compared to $2.93 per GJ in fiscal 1999. -28- REVENUE. Our gross revenue totalled $213.4 million in fiscal 2000, an increase of 120% from $97.0 million in fiscal 1999. This increase was attributable to a combination of higher production of natural gas, crude oil and natural gas liquids, which accounted for 30% of the increase, and much stronger realized commodity prices, which accounted for the remaining 70% of the increase. ROYALTIES. Our royalty commitments, after royalty credits, increased in fiscal 2000 to a total of $44.7 million, up 178% from $16.1 million in fiscal 1999. This increase was attributable to a combination of higher production volumes and the effect of the sliding scale royalty structure in Alberta, which imposes higher royalty rates at higher product prices. Our average royalty rate on our combined production was 20.9% in fiscal 2000, compared to 16.6% in fiscal 1999. OPERATING COSTS. Our operating costs increased to $31.6 million in fiscal 2000 from $20.5 million in fiscal 1999, largely as a result of increases in our production attributable to higher initial costs associated with new production and to general increases in costs of goods and services associated with the industry's high level of field activity. On a barrel of crude oil equivalent basis, operating costs increased to $5.32 per boe in fiscal 2000, an increase of 20% from the $4.45 per boe in fiscal 1999. GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses increased 40% to $5.9 million in fiscal 2000 from $4.2 million in fiscal 1999. This increase was attributable to higher levels of staffing required by our increased level of activity. On a barrel of oil equivalent basis, general and administrative costs were $1.00 in fiscal 2000, an increase of 9% from $0.92 in fiscal 1999. In fiscal 2000 these expenses represented 2.8% of gross revenues. INTEREST EXPENSE. During fiscal 2000, we incurred an interest rate of approximately 7.0% on our average outstanding bank debt, resulting in a total interest expense of $12.8 million, up from $6.9 million in fiscal 1999. The increase was attributable to both a higher average interest rate and a higher average outstanding bank debt. DEPLETION AND DEPRECIATION. Our depletion and depreciation expenses increased to $41.8 million in fiscal 2000 from $20.2 million in fiscal 1999. On a barrel of oil equivalent basis, depletion and depreciation amounted to $7.04 per boe in fiscal 2000, compared to $4.37 per boe in fiscal 1999. The change in accounting policy to account for future income taxes payable discussed below resulted in an increase in the carrying value of our assets of $68.1 million, and in turn generated an incremental increase in the annual depletion and depreciation rate of approximately $1.40 per boe. The remaining increase resulted from higher production levels and increased finding and development costs for new reserve additions. INCOME TAXES. Our tax expense of $0.9 million for fiscal 2000 consisted of a Large Corporation Tax and was 347% higher than the $0.2 million for fiscal 1999. Future income taxes for fiscal 2000 were $35.7 million, an increase of 203% for the same period in 1999. Effective January 1, 2000, we adopted the new recommendations of the Canadian Institute of Chartered Accountants with respect to accounting for future income taxes. Under the new recommendations the liability method of tax allocation is used, which is based upon the difference between financial and tax bases of assets and liabilities. Previously, the deferral method was used, which is based upon differences between the timing of reporting income and expenses for financial and income tax purposes. We have adopted this change in accounting policy retroactively, without restating our financial statements of prior periods. As a result, we recorded a reduction in retained earnings of $0.4 million, an increase in property and equipment of $68.1 million and an increase in the future income tax liability of $68.5 million, as at January 1, 2000. The adjustments were mainly the result of future tax costs relating to acquisitions where the tax base acquired was less than the purchase price, and of the tax consequence of the issuance of flow-through share issues. NET EARNINGS. For all of the reasons specified above, net earnings increased by 134% from $17.1 million in fiscal 1999 to $40.1 million in fiscal 2000. LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS. Our cash flow from operating activities (which refers to cash flow from operations after considering changes in non-cash operating working capital), for the first six months of fiscal 2002 decreased by 45% to $51.1 million, -29- compared to $92.4 million for the first six months of fiscal 2001, primarily as a result of lower commodity prices. Adjustments to our $14.5 million net earnings for the first six months of 2002, to reconcile it to net cash flow from operating activities, include $26.4 million in depletion and depreciation, $9.3 million in future income taxes, $0.3 million in amortization of deferred financing charges, $8.5 million in unrealized foreign exchange gain and $9.1 million in changes in non-cash operating working capital. Our cash flow from operating activities for fiscal 2001 increased by 16% to $121.1 million, compared to $104.2 million for fiscal 2000. Adjustments to our $55.6 million net earnings for fiscal 2001, to reconcile it to net cash flow from operating activities, include $50.5 million in depletion and depreciation, $22.2 million in future income taxes and $7.3 million in changes in non-cash operating working capital. We generated cash flow from operating activities of $104.2 million in fiscal 2000, an increase of 176% from $37.8 million in fiscal 1999. Adjustments to our $40.1 million net earnings for fiscal 2000 to reconcile it to net cash flow from operating activities included $41.8 million in depletion and depreciation, $35.7 million in future income taxes and $13.3 million in changes in non-cash operating working capital. In fiscal 1999, we generated cash flow from operating activities of $37.8 million, an increase of 205% from $12.4 million in fiscal 1998. Adjustments to our $17.1 million of net earnings for fiscal 1999, to reconcile it to net cash flow from operating activities, included $20.2 million in depletion and depreciation, $11.8 million in future income taxes and $5.2 million in changes in non-cash operating working capital. We continually reinvest internally generated cash flow from operating activities into capital expenditures in order to fund the growth of our exploration and development projects and to further consolidate our undeveloped land base. On a monthly basis, our cash management policy is designed to balance exploration and development capital expenditures with our cash flow from operating activities. However, due to the timing of the occurrence of our capital expenditures, there are occasions when we may disclose a positive ending cash balance for a respective reporting period, with such cash being reinvested into capital expenditures in subsequent reporting periods. Our net cash used in investing activities for the first six months of fiscal 2002 was $69.7 million, a decrease of $8.5 million from the first six months of fiscal 2001. Our principal uses of cash for the first six months of 2002 included $41.4 million in oil and natural gas property expenditures. Our net cash used in investing activities for fiscal 2001 was $176.1 million, an increase of $57.0 million from fiscal 2000. Our principal uses of cash for fiscal 2001 included $148.0 million in oil and natural gas property expenditures and $29.7 million in cash acquisition expenses for our Hornet acquisition. Our net cash used in investing activities during fiscal 2000 was $119.1 million, a decrease of $16.9 million from fiscal 1999. Our principal uses of cash during fiscal 2000 included $118.2 million in oil and natural gas property expenditures and $0.3 million in cash acquisition expenses for our new property acquisitions. Our net cash used in investing activities during fiscal 1999 was $111.0 million, an increase of $33.3 million in fiscal 1998. Our principal uses of cash during fiscal 1999 included $71.2 million in oil and natural gas property expenditures and $49.8 million in cash acquisition expenses for our acquisition of Coparex. In mid-2001, we renegotiated our senior credit facilities with a syndicate of Canadian financial institutions resulting in an increase to $240 million in our credit facilities from $192 million at the beginning of the year. Upon completion of the offering, we repaid all amounts outstanding under our senior credit facilities, the size of our senior credit facilities was reduced and approximately $168.0 million is currently available for borrowing under these facilities. Borrowings under our senior credit facilities are limited by a borrowing base amount that was initially established by and is periodically redetermined by the lenders. This borrowing base amount is the lenders' estimate of the present value of the future net cash flow from certain of our petroleum and natural gas properties. Our current borrowing base comprises our senior credit facilities, which currently consist of a $158.0 million revolving credit facility and a $10.0 million working capital facility, aggregating to $168.0 million. At June 30, 2002, we had no outstanding borrowings under our working capital facility. Our senior credit facilities bear interest at our lenders' prime rate or at the bankers' acceptance rate or LIBOR plus a margin based on our ratio of total consolidated debt to cash flow that is currently set at 0.625%, 1.625% and 1.625%, respectively. On June 30, 2002, the actual interest rate on our senior credit facilities was 4.875%. These facilities are secured by a charge against all of our assets. -30- In March 2002, we obtained regulatory approval from The Toronto Stock Exchange to renew our share buy-back program to buy back up to approximately 5.4 million of our outstanding common shares. The buy back program was renewed for a 12-month period, which commenced on March 8, 2002 and ends on March 7, 2003 (unless terminated earlier by us). The Toronto Stock Exchange rules allow us to buy back up to the greater of (i) 5% of our issued and outstanding common shares, excluding any shares held by or on behalf of us on the date of acceptance of the notice of our issuer bid to The Toronto Stock Exchange or (ii) 10% of the public float of such shares. The public float means the number of issued and outstanding common shares, less the number of shares controlled by our senior officers, directors, principal shareholders and the number of common shares that are pooled, escrowed or non-transferable. Our management continuously monitors the price of our common shares and decides when it is appropriate for us to buy back such shares. For the year ended December 31, 2001, we had repurchased 4,206,000 common shares under this buy back program for $17.8 million. We have funded our repurchases of common shares from cash generated from operations and drawings under our senior credit facilities. Net capital expenditures for the first six months of fiscal 2002 totalled $41.5 million, a decrease of 47% from the total $78.3 million for the first six months of fiscal 2001. A general decrease in activities, including drilling, seismic and corporate and property acquisitions, accounted for the lower expenditures. Net capital expenditures for fiscal 2001 totalled $190.4 million, an increase of 60% from the total of $118.8 million for the fiscal 2000. During fiscal 2001, our drilling program continued to focus on deeper targets, which resulted in a higher average drilling cost per well. During the year, our drilling program was successful in adding a total of 12.2 million boe of proved reserves. We continue to invest significantly in undeveloped land and seismic, which accounted for 14% of our total capital expenditures during this period, in order to enhance our exploration and development prospects. Capital expenditures in fiscal 2000 totalled $118.8 million, as compared to $106.2 million in fiscal 1999. Our capital expenditures in fiscal 2000 were consistent with our strategy for long-term growth, as we made significant investments in undeveloped land, seismic, production facilities and exploration drilling necessary for continued value creation. In comparison to fiscal 1999, capital expenditures incurred on property, undeveloped land and seismic increased by 81%, expenditures on production equipment and facilities increased by 131% and our capital investments in exploration, exploitation and development projects across our operating areas increased by 47%. Exploratory drilling and completion expenses totalled approximately $45.7 million in fiscal 2000, 68% of the total $66.7 million expended on exploration, exploitation and development. During that year, our drilling program succeeded in adding 11.5 million boe of proved reserves. Our capital expenditures totalled $69.9 million in fiscal 1998. The table below sets out our capital expenditures by category over the past three years, the first three months of fiscal 2001 and the first three months of fiscal 2002.
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30, --------------------------------------------- -------------------------- 1999 2000 2001 2001 2002 ------------ ---------- ------------- ---------- ---------- (THOUSANDS OF DOLLARS) (unaudited) Property, lease and seismic expenditures... $ 12,859 $ 23,241 $ 31,450 $ 28,463 $ 8,384 Exploration, development and exploitation.. 45,359 66,695 84,658 36,009 23,102 Production equipment and facilities........ 12,090 27,901 34,447 13,752 9,906 Other...................................... 1,415 684 10,243 69 99 ----------- ---------- ----------- ----------- ----------- Total exploration and development expenditures............................ 71,723 118,521 160,798 78,293 41,491 Acquisitions............................... 49,833 241 29,669 -- -- Dispositions............................... (15,351) -- -- -- -- ----------- ---------- ----------- ----------- ----------- Net capital expenditures............... $ 106,205 $ 118,762 $ 190,467 $ 78,293 $ 41,491 =========== ========== =========== =========== ===========
In the past we have partially grown through acquisitions and we regularly evaluate opportunities to acquire properties or companies. If we decide in the future to make a significant acquisition for cash, we might be required to raise capital via debt and/or equity financings in order to complete the acquisition. The purchase price of the Hornet acquisition was approximately $29.1 million in cash plus the assumption of $10.9 million in debt, a working capital deficiency of $1.5 million and transaction costs of $0.5 million. We funded the cash portion of the Hornet acquisition out of working capital. We believe that funds generated from our operations, together with borrowings under our senior credit facilities, will be sufficient to finance our current operations and planned capital expenditures for the next three years. We anticipate that our annual capital expenditures over the next few years will increase somewhat from our expenditures in fiscal 2001. -31- Management determines its capital expenditure program based on the annual budget, including budgeted cash flow from operations, and closely monitors changes throughout the year. Our 2002 capital expenditure program is focused in our core areas and is based on a conservative pricing scenario, in that our budgeted commodity price assumptions for both oil and natural gas are substantially lower than actual prices realized during the prior year, 23% and 30%, respectively. In fiscal 2001, the West Texas Intermediate oil benchmark price ("WTI") averaged US$25.91 per barrel and the NYMEX natural gas price averaged US$4.05 per mcf. Our original 2002 budget outlined a plan to drill a minimum of 70 to 75 wells and to incur capital expenditures of $100 million, based upon average commodity price assumptions of WTI at US$20.00 per barrel of oil and US$2.85 NYMEX per mcf of natural gas. Given the recent increase in commodity prices (currently the WTI oil price is approximately US$29.00 per barrel and the NYMEX natural gas price is approximately US$3.80 per mcf), we anticipate generating higher cash flow from operations in 2002 than originally budgeted. As a result, we are planning to increase our capital expenditures program this year and incur approximately $115 million in capital expenditures, consistent with this anticipated increase in cash flow from operations. Currently, we intend to allocate approximately 35% of our capital expenditures in fiscal 2002 to exploration activities and approximately 65% to development activities. Currently, we expect to spend 60% of our capital expenditures in our southern Alberta core area. The timing of most of our capital expenditures is discretionary, and we have no material long-term capital expenditure commitments. It is likely that in the future we will be required to raise additional capital via debt and/or equity financings in order to fully realize our strategic goals and business plans. Our ability to raise additional capital will depend upon a number of factors, such as general economic and market conditions, that are beyond our control. If we are unable to obtain additional financing or to obtain it on favorable terms, we might be required to forego attractive business opportunities. We believe our working capital, including the amounts available to us from our working capital credit facility, is sufficient to sustain our operations. However, our ability to make payments on and to refinance our indebtedness, including the notes, and to fund planned capital expenditures will depend on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our senior credit facilities in an amount sufficient to enable us to pay our indebtedness, including these notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including these notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our senior credit facilities and the notes, on commercially reasonable terms or at all. See "Risk Factors". HEDGING POLICY MARKET RISK. We are exposed to a variety of market risks, including changes in commodity prices, foreign currency exchange rates and interest rates. We use various risk management activities to mitigate the effects of these market risks. We do not use derivative instruments for speculative or trading purposes. FOREIGN CURRENCY EXCHANGE RISK. Our financial results are exposed to fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar. Crude oil, and to a large extent, natural gas prices, are based upon reference prices denominated in U.S. dollars, while the majority of our expenses are denominated in Canadian dollars. The amounts we received from the offering of the initial notes were in U.S. dollars and our payment of interest on and principal of the notes will be made in U.S. dollars. An increase or decrease of $0.10 per US$1.00 would increase or reduce, respectively, our semiannual payments of interest on the notes by approximately $817,000 and our payment of the principal of the notes by $16.5 million. From time to time, we may enter into agreements to fix the exchange rate of Canadian dollars to U.S. dollars. We do so in order to offset the risk of the reduction in our revenues that would occur if the Canadian dollar increases in value compared to the U.S. dollar. Conversely, we may enter into agreements to fix the exchange rate to protect the principal and interest payments on our U.S. dollar denominated liabilities. INTEREST RATE RISK. We are exposed to changes in interest rates, because our senior credit facilities bear interest at our lenders' prime lending rate, or at the banker's acceptance rate, or at the London Interbank Offered Rate (referred to as LIBOR) plus a margin based on our ratio of total consolidated debt to cash flow. Thus, our cost of borrowing fluctuates and the applicable rate on any borrowings under this facility may be sensitive to changes in our lender's prime rate, the banker's -32- acceptance rate and the LIBOR rate. The fixed interest rate nature of our US$165 million senior notes, for the most part, mitigates this exposure. There are currently no amounts outstanding on our credit facilities. The majority of our long-term debt has a fixed interest rate and we periodically use interest rate swaps to manage our debt serving costs. COMMODITY PRICE RISK. Our financial results can be significantly affected by the prices received for our crude oil and natural gas production, as commodity prices fluctuate widely in response to changing market forces. We expect this pricing volatility to continue. From time to time, we seek to reduce our exposure to commodity price risk by entering into long-term production contracts and commodity hedging contracts (in which we agree to sell a fixed amount of oil or natural gas at a specified date in the future), to hedge our commodity price risk. We recognize our realized gains or losses from our hedging activities as crude oil and natural gas production revenue, when the associated production occurs. During fiscal 2000, approximately 39% of our natural gas production was committed to aggregators and received a price lower than AECO (spot market price). In addition, we sold 549,000 barrels of crude oil at a price of US$21.75 per barrel for delivery in 2000. Our average crude oil price of $33.92 per barrel, realized for the 2000 fiscal year, is net of a hedging opportunity cost of $13.94 per barrel relating to the 549,000 barrels of production hedged. Additionally, in January 2000, we entered into an agreement to sell 7.1 mmcf/d of natural gas pursuant to contracts at the then market price of $3.55 per mcf. In total, these contracts had an opportunity cost of $7.7 million for fiscal 2000. None of our fiscal 2001 crude oil production was hedged. With respect to natural gas, we contracted 9.5 mmcf/d of gas, from November 1, 2000 through March 31, 2001, under a costless collar arrangement, having a floor of $5.80 per mcf and a ceiling of $9.54 per mcf. A costless collar is a hedging arrangement, purchased at no cost to us, whereby we will receive a price within a price collar or range for oil and natural gas production. Additionally, we contracted 5.7 mmcf/d from April 1, 2001 through to October 31, 2001, under a costless collar arrangement, having a floor price of $6.85 per mcf and a ceiling of $8.63 per mcf. In July, 2001 with the Hornet acquisition, we acquired a contract to sell 4,000 GJ/d of natural gas to January 31, 2002 at an AECO fixed price of $4.89 per GJ. In total, these contracts produced a gain of $3.7 million that was included in oil and gas revenues for the year. Currently for fiscal 2002 we have hedged approximately 22% of our current production. The table below sets forth our forward sales contracts and other hedging arrangements for 2002 and 2003, that were outstanding as at June 30, 2002, and shows the unrecognized gain or loss on each such arrangement as if the crude oil or natural gas had been sold at the market price on June 30, 2002:
HEDGING TRANSACTION PERIOD AMOUNT PRICE RANGE (DOLLARS IN THOUSANDS) UNRECOGNIZED (GAIN) OR LOSS AS AT JUNE 30, 2002 --------------------------- ------------------------ ----------------- -------------------- ------------------------ Natural Gas Collar April 2002 - October 15,000 GJ/d @ $3.83/GJ-$5.45/GJ $ (818) 2002 AECO Natural Gas Fixed Price May 2002 - October 2002 5,000 GJ/d @ $4.50/GJ $ (683) Contract AECO Crude Oil Collar May 2002 - December 1,500 bbls/d US $23.83/bbl - $ - 2002 US $28.00/bbl Crude Oil Fixed Price May 2002 - December 500 bbls/d US $24.40/bbl $ 111 Contract 2002 Natural Gas Collar November 2002 - March 5,000 GJ/d @ $4.50/GJ - $7.85/GJ $ - 2003 AECO
The table below sets forth forward sales contracts and other hedging arrangements for 2002 and 2003, that are currently outstanding and were entered into by us subsequent to June 30, 2002. -33-
HEDGING TRANSACTION PERIOD AMOUNT PRICE RANGE ----------------------------- --------------------------- -------------------- ------------------------------ Natural Gas Collar November 2002 - March 2003 20,000 GJ/d @ AECO $4.00/GJ - $6.55/GJ Crude Oil Collar January 2003 - December 500 bbls/d US$23.50/bbl - US$27.00/bbl 2003 Crude Oil Fixed Price January 2003 - December 500 bbls/d US$25.00/bbl Contract 2003
No other hedging contracts are in place for the year 2003. RECENT ACCOUNTING PRONOUNCEMENTS On July 20, 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") 141, BUSINESS COMBINATIONS, and SFAS 142, GOODWILL AND INTANGIBLE ASSETS. SFAS 141 is effective for all business combinations completed after June 30, 2001. SFAS 142 is effective for fiscal years beginning after December 15, 2001; however, certain provisions of this statement apply to goodwill and other intangible assets acquired between July 1, 2001 and the effective date of SFAS 142. Major provisions of these statements and their effective dates for us are as follows: o All business combinations initiated after June 30, 2001 must use the purchase method of accounting. The pooling of interest method of accounting is prohibited except for transactions initiated before July 1, 2001. o Intangible assets acquired in a business combination must be recorded separately from goodwill if they arise from contractual or other legal rights or are separable from the acquired entity and can be sold, transferred, licensed, rented or exchanged, either individually or as part of a related contract, asset or liability. o Goodwill, as well as intangible assets with indefinite lives, acquired after June 30, 2001, will not be amortized. Effective January 1, 2002, or the first day of the fiscal year of SFAS 142 implementation, all previously recognized goodwill and intangible assets with indefinite lives will no longer be subject to amortization. o Effective January 1, 2002, or the first day of the fiscal year of SFAS 142 implementation, goodwill and intangible assets with indefinite lives will be tested for impairment annually and whenever there is an impairment indicator. o All acquired goodwill must be assigned to reporting units for purposes of impairment testing and segment reporting. Management's assessment is that these statements do not have a material impact on our financial position or results of operations. In July, 2001, the FASB issued SFAS No. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS. This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement applies to all entities. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) the normal operation of a long-lived asset, except for certain obligations of lessees. This statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. We are evaluating the impact of the adoption of this standard and we have not yet determined the effect of adoption on our financial position and results of operations. In August, 2001, the FASB issued SFAS No. 144, ACCOUNTING FOR THE IMPAIRMENT OR DISPOSAL OF LONG-LIVED ASSETS. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes FASB Statement No. 121, ACCOUNTING FOR THE Impairment OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF. The provisions of the statement are effective for financial statements issued for fiscal years beginning after December 15, 2001. Management's assessment is that these statements do not have a material impact on our financial position or results of operations. -34- In July 2002, the FASB issued SFAS No. 146, ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES. SFAS 146 nullifies EITF 94-3, LIABILITY RECOGNITION FOR CERTAIN EMPLOYEE TERMINATION BENEFITS AND OTHER COSTS TO EXIT AN ACTIVITY (including Certain Costs Incurred in a Restructuring). SFAS 146 requires the recognition of a liability for costs associated with exit or disposal activities when a liability is incurred; that is, the costs meet the definition of a liability in accordance with Concepts Statement 6, ELEMENTS OF FINANCIAL STATEMENTS. The statement also provides guidance on the required disclosures of exit and disposal activities. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. BUSINESS THE COMPANY We are an independent public company actively engaged in the exploration, development and production of natural gas, natural gas liquids and crude oil in western Canada. We have established our current operational base through a combination of a program of full-cycle exploration and strategic acquisitions. This involves: o establishing core geographic operating areas through strategic acquisitions; o developing significant operational and technical expertise through exploration and development activities; o acquiring strategic control over infrastructure; and o reinvesting operating cash-flow to further consolidate our position in each of our core areas and to further grow our inventory of drilling prospects. We began operations in 1993 with a small technical team and a large seismic database. Through a series of acquisitions and continued drilling success, we have established total proved reserves of 321 bcfe as of December 31, 2001. Approximately 82% of our total proved reserves are natural gas and approximately 89% of our total proved reserves are proved developed. As of June 30, 2002, we held working interests in 826,591 (635,371 net) acres of undeveloped land and we held working interests in 1,056 gross (437.2 net) producing wells in western Canada. We currently focus our operations in four geographic areas: o SOUTHERN ALBERTA-- ESTABLISHED IN 1993: We have one of the largest land positions in the area, with more than 452,488 net acres (330,001 net undeveloped acres) of gas-prone lands. Concentrated in and around our net acreage, there are approximately, 1,800,000 acres or 2,850 sections of land. We own approximately 25% of these lands, which represents the largest percentage of land ownership among oil and gas companies operating within the area. These lands are primarily gas-prone, with 64% of producing wells within the area being natural gas wells. We operate substantially all of our production and have long-term access to necessary processing facilities in this area. We believe that our land ownership position in this area will provide us with a multi-year inventory of exploration and development prospects. This area represented 69% of our proved reserves as of December 31, 2001, 52% of our net undeveloped land as of June 30, 2002, 53% of our production for the year ended December 31, 2001 and 55% of our production for the six months ended June 30, 2002. o WEST CENTRAL ALBERTA -- ESTABLISHED IN 1998: This area has significant natural gas and light oil production. We plan to increase our long-life, high-quality, light oil production through a variety of exploitation techniques and to pursue multi-zone gas exploration targets. This area represented 17% of our proved reserves as of December 31, 2001, 18% of our net undeveloped land as of June 30, 2002, 26% of our production for the year ended December 31, 2001 and 24% of our production for the six months ended June 30, 2002. -35- o PEACE RIVER ARCH-- ESTABLISHED IN 1998: This north-central Alberta core area offers us a range of opportunities, including lower-risk exploitation, secondary recovery efforts and pure natural gas exploration. Our light oil development program, which consists of secondary recovery through water flooding of the reservoir and infill drilling, provides us with predictable ongoing production and an extension of the area's reserve life. We plan to expand and consolidate our operations in this core area by acquiring additional land and increasing control of operatorship and infrastructure. This area represented 13% of our proved reserves as of December 31, 2001, 10% of our net undeveloped land as of June 30, 2002, 18% of our production for the year ended December 31, 2001 and 19% of our production for the six months ended June 30, 2002. o NORTHERN ALBERTA-- ESTABLISHED IN 1996: Within the Rainbow/Zama area in northern Alberta, we have a large undeveloped land base consisting of more than 96,000 net acres that we believe provides us with multi-zone exploration opportunities. This area is relatively under-explored due to its remoteness. Industry interest, however, has heightened with increased drilling and infrastructure activity on lands adjacent to ours. Since 1996, drilling activity and infrastructure construction has increased considerably in the Rainbow/Zama area. In 1996, a total of 63 wells were drilled by the oil and gas industry, as compared to approximately 225 wells in fiscal 2001. Moreover, a major natural gas pipeline was installed in fiscal 2000 which transports gas through our main block of lands. More recently, two other oil and gas companies have installed natural gas gathering pipelines in the area. This area represented 1% of our proved reserves as of December 31, 2001, 15% of our net undeveloped land as of June 30, 2002, 3% of our production for the year ended December 31, 2001 and 2% of our production for the six months ended June 30, 2002. In addition to our four core areas discussed above, we have 5% of our net undeveloped land in minor properties outside of our four geographic core areas. These lands are located in northeastern British Columbia, northeastern Saskatchewan and southern Manitoba. These minor properties were acquired primarily as a result of acquisitions of corporations whose primary assets were in one or more of our core areas. Currently, less than 1% of our production comes from these minor properties. BUSINESS STRATEGY Our strategy is to grow our reserves and increase our production in our four core geographic areas and other areas where we have technical expertise. Our senior management team has significant technical and operational expertise with an average of 20 years of experience in one or more of our core areas. Our senior management team has demonstrated its ability to execute our strategy while exercising financial discipline. Through effective leadership, our senior management team has enabled us to deliver strong growth in both the size of reserves and the quantity of our production while preserving and strengthening our financial position. Since 1999, our proved reserves and production have grown on a compounded annual rate basis of 14% and 19%, respectively, while EBITDA has increased 59% and our ratio of EBITDA to interest expense over this three year period was 10.1 times. CONCENTRATE ON FOUR CORE GEOGRAPHIC AREAS. We currently operate in four core geographic areas which provides us with a balanced portfolio of exploration and development prospects. The natural gas and light oil development projects in our portfolio include lower decline reserves. Our portfolio of lower decline reserves is reflected in our high proved reserve life index of 8.2 years for fiscal 2001. Our reserves decline at a lower rate which will allow us to generate a steady stream of production over the next several years. The cash flow from these projects is used to fund our on-going, multi-zone, deep gas exploration program. FOCUS ON NATURAL GAS. We have gained considerable technical expertise and achieved significant success in exploring for deeper and larger natural gas reservoirs. In 2001, our average well depth was approximately 1,790 meters, which is significantly deeper than the Alberta oil and gas industry average well depth of approximately 1,000 meters. Notwithstanding our increased focus on drilling for deeper gas reservoirs, we were able to achieve a drilling success rate of 76% in 2001, as compared to our drilling success rate of 61% in 1998. We plan to continue to focus on finding and developing long-life natural gas reserves. Our proved reserves as of December 31, 2001 of 321 bcfe were approximately 82% natural gas with an estimated reserve life of 8.2 years at that date. -36- PURSUE FULL-CYCLE EXPLORATION COMPLEMENTED BY SELECTIVE ACQUISITIONS. We plan to continue to reinvest internally generated cash flow to fund the growth of our exploration prospects and development projects and to further consolidate our undeveloped land base to maintain a growing inventory of drilling prospects in our core geographic areas. Since January 1, 1997, we have replaced 327% of our aggregate production with proved reserve additions, growing our existing proved reserve base from 48 bcfe at December 31, 1996 to 321 bcfe at December 31, 2001, at an average cost of $9.25 per boe. We have also successfully completed and integrated a series of strategic acquisitions to grow our proved reserves and production base and enhance our technical expertise in our core areas. Depending on commodity price cycles, we may defer exploration projects and enhance our operations and prospects through strategic acquisitions. CONTROL OF INFRASTRUCTURE AND OPERATORSHIP. We believe that control over gathering and processing infrastructure and operatorship of drilling programs will continue to be critical to the success of our full-cycle exploration program. We currently own or have access to all critical infrastructure in each of our three primary producing areas. We operate approximately 92% of our existing production and, as of June 30, 2002 we had a 77% average working interest in our undeveloped lands. This position allows us to exercise discretion in determining the timing and methodology of our ongoing exploration and development programs. We will continue to consolidate our position in our core areas to maximize operating efficiencies and maintain control over our ongoing capital programs. MAINTAIN A LARGE PORTFOLIO OF UNDEVELOPED LAND. We have assembled a significant portfolio of undeveloped land (working interests in 826,591 (635,371 net) acres of undeveloped land, as of June 30, 2002) and complementary seismic data in our core areas. We believe that our existing portfolio of undeveloped land is sufficient to produce at least three years of internally generated exploration and development prospects. Our extensive internal prospect inventory is based on the large portfolio of undeveloped land that we hold for drilling activities. With 635,371 net acres, or approximately 1,000 sections of undeveloped land, we can drill approximately 1,000 wells (each well is located on approximately 1 section of land). Assuming that only half of these lands are prospective for oil and natural gas, approximately 500 wells could be drilled, which would provide us with sufficient land for exploration and development activities for the next three to five years. MAINTAIN FINANCIAL FLEXIBILITY. We are committed to maintaining financial flexibility to allow us to pursue our full-cycle exploration program in periods of low commodity prices. We also intend to maintain the flexibility to respond to opportunities for strategic acquisitions as they arise. We have historically funded our capital program through internally generated cash flow and have financed acquisitions through bank debt, the issuance of common stock, or a combination thereof. SEASONALITY OF THE OIL AND GAS INDUSTRY The exploration for and development of oil and gas reserves is dependant on access to areas where operations are to be conducted. Oil and gas industry operations in Western Canada are affected by road bans imposed from time to time, during the break-up and thaw period in the spring. Road bans are also imposed due to snow, mud and rock slides and periods of high water which can restrict access to our well sites and production facility sites. Additionally, demand for crude oil and natural gas varies seasonally. Demand for natural gas is greatest in the winter months to meet peak heating demand, which demand for gasoline and the types of crude oil most used to produce it is higher in summer months. SUBSIDIARIES Our wholly owned corporate subsidiaries are identified in the chart below. [GRAPHIC OMITTED] Compton Petroleum Corporation ----------------------------- 100% 100% 100% ---- ---- ---- ------------------ ------------------- ------------------- Hornet Energy Ltd. 867791 Alberta Ltd. 899776 Alberta Ltd. (a Canadian (an Alberta (an Alberta Corporation) Corporation) Corporation) ------------------ ------------------- ------------------- -37- Effective January 31, 2001, a general partnership called Compton Petroleum was formed under the laws of Alberta, between us and our wholly owned subsidiary 867791 Alberta Ltd. On July 16, 2001, the partnership agreement was amended to include Hornet Energy Ltd. Each partner has contributed a majority of its assets to the partnership. The majority of our operations are carried out through the partnership. We are the general partner of the partnership and have a 90.9% interest. Hornet Energy Ltd. and 867791 Alberta Ltd. are both limited partners and have a 5.3% and 3.8% interest, respectively. RECENT DEVELOPMENTS Currently for fiscal 2002 we have hedged approximately 22% of our current production. With respect to natural gas, we contracted 15,000 GJ/d at AECO from April 2002 through October 2002 a costless collar arrangement having a floor of $3.83 per GJ and a ceiling of $5.45 per GJ. Additionally, we sold 5,000 GJ/d at AECO from May 2002 to October 2002 at a fixed price of $4.50 per GJ. For crude oil, we have sold 500 bbls/d from May 2002 to December 2002 at a fixed price of US$24.40 per barrel. Additionally, we contracted 1,500 bbls/d from May 2002 to December 2002 under a costless collar arrangement having a floor price of US$23.83 per barrel and a ceiling of US$28.00 per barrel. We also have contracted 5,000 GJ/d of natural gas at AECO from November 1, 2002 to March 31, 2003 under costless collar arrangements having a floor of $4.50 per GJ and a ceiling of $7.85 per GJ. Additionally, we contracted 20,000 GJ/d at AECO from November 1, 2002 to March 31, 2003 under a costless collar arrangement having a floor of $4.00 per GJ and a ceiling of $6.55 per GJ. For fiscal 2003, with respect to crude oil, we contracted 500 bbls/d from January 2003 to December 2003 under a costless collar arrangement having a floor price of US$23.50 per barrel and a ceiling of US$27.00 per barrel. We have also sold 500 bbls/d from January 2003 to December 2003 at a fixed price of US$25.00 per barrel. No other hedging contracts are in place for fiscal 2003. Our average daily production for the first six months of 2002 was 19,193 boe/d, an increase of 13% over the 17,009 boe/d for the comparable period in 2001. Commodity prices realized during the period, however, were significantly lower than the historically high prices realized during the first six months of 2001. Both the West Texas Intermediate oil benchmark price and the AECO natural gas price index decreased substantially from the first six months of 2001, down 16% and 57%, respectively. This dramatic drop in commodity prices had an adverse impact on our first six months 2002 earnings and cash flow. PRINCIPAL PROPERTIES The following table summarizes the net daily production from our four core operating areas for the six-month period ended June 30, 2002:
NATURAL CRUDE OIL GAS LIQUIDS NATURAL GAS TOTAL ------------ ------------ ------------ ---------- (BBLS/D) (BBLS/D) (MMCF/D) (BOE/D) Southern Alberta........... 117 996 57.2 10,633 West Central Alberta....... 1,535 355 16.3 4,600 Peace River Arch........... 1,573 238 10.8 3,620 Northern Alberta........... 102 33 1.2 340 ------------ ------------ ------------ ---------- Total.................. 3,327 1,622 85.5 19,193 ============ ============ ============ ==========
The following table sets forth our percentage of revenue for natural gas, crude oil and natural gas liquids for each of our principal properties during each of the years ended December 31, 2000, December 31, 2001 and for the six-month period ended June 30, 2002. YEAR ENDED DECEMBER 30, 2000 ------------------------------------------- NATURAL GAS CRUDE OIL NATURAL GAS LIQUIDS ------------ ----------- ------------ Southern Alberta.......... 53% 14% 64% West-Central Alberta...... 24 65 25 Peace River Arch.......... 22 19 11 Northern Alberta.......... 1 2 0 ------------ ----------- ------------ Total................. 100% 100% 100% ============ =========== ============ -38- YEAR ENDED DECEMBER 31, 2001 ------------------------------------------- NATURAL GAS CRUDE OIL NATURAL GAS LIQUIDS ------------ ----------- ------------ Southern Alberta.......... 65% 3% 69% West-Central Alberta...... 20 49 21 Peace River Arch.......... 13 41 7 Northern Alberta.......... 2 7 3 ------------ ----------- ------------ Total................. 100% 100% 100% ============ =========== ============ SIX MONTH PERIOD ENDED JUNE 30, 2002 ------------------------------------------- NATURAL GAS CRUDE OIL NATURAL GAS LIQUIDS ------------ ----------- ------------ Southern Alberta.......... 67% 4% 61% West-Central Alberta...... 19 46 22 Peace River Arch.......... 13 47 15 Northern Alberta.......... 1 3 2 ------------ ----------- ------------ Total................. 100% 100% 100% ============ =========== ============ SOUTHERN ALBERTA Our southern Alberta properties cover an extensive area commencing from Calgary's southern city limit and running 150 kilometres south through the Gladys, Okotoks-Mazeppa and Hooker areas to the Keho Lake area. In 1993, we commenced operations in the Gladys area, where we are now one of the largest landowners and where we operate the majority of our producing wells. We have significantly expanded our land and production base in the Okotoks-Mazeppa, Hooker and Keho Lake areas through property and facility acquisitions, purchases of land from the government and private owners acquisition of interests in properties produced by other companies and exploration activities. In particular, we have developed a very extensive Basal Quartz play at Hooker. The Basal Quartz play is an incised valley system containing Cretaceous sandstone reservoir rock that we believe extends over at least 60 kilometers and holds large quantities of liquids-rich, low decline natural gas reserves at 2,400 to 3,400 meter depths. In the fall of 2000, we acquired an additional 39,047 acres at Aphrodites area, which is to the south of Hooker. As of June 30, 2002, we had working interests in 569,038 gross (452,488 net) acres of land in the southern Alberta area at an average working interest of 80%. In the Foothills, an extension of the southern Alberta core area, we have acquired 100% working interests in 47,930 gross (47,930 net) acres of land on the Tsuu T'ina First Nation Reservation immediately west of Calgary. As well, we have working interests in 6,002 gross (4,202 net) acres of land 50 kilometres northwest of Calgary with an average working interest of 70%. We have a 100% working interest in a 3.2 mmcf/d natural gas plant at Keho Lake, and an 8.2% working interest in a 40 mmcf/d natural gas plant at Vulcan. We have a 100% working interest in three crude oil batteries at Keho Lake, Gladys and Connemara. As well, we have significant working interests in strategic gathering and compression systems, including a 100% interest at Centron, an 80% interest at High River and a 93% interest at Brant. Our southern Alberta properties will continue to be a key focus for our exploration, exploitation and development program. Since inception, we have focused on this core area and we have secured a large land base, substantial seismic information, ownership or access to infrastructure and processing capacity, high working interests and operatorship. Having established long-term access to necessary infrastructure in this area, combined with a multi-year inventory of exploration and development prospects, we believe that we are well positioned to explore, exploit and develop our southern Alberta properties to their full potential. We have focused on exploiting and developing multiple natural gas bearing reservoirs in this area, particularly in the Basal Quartz, Crossfield, Belly River, Ellerslie and Turner Valley formations. -39- WEST-CENTRAL ALBERTA As of June 30, 2002, we had working interests in 406,774 gross (178,705 net) acres of land in the west central Alberta area with a 44% working interest. We have working interests in 55,040 gross (43,315 net) acres of land, with an average working interest of 79%, in the Bigoray, Pembina, Tomahawk and Rosevear areas, approximately 100 kilometres west of Edmonton. Production occurs from six light crude oil pools, namely the Nisku D, E and F pools, the Cardium B pool, the Pekisko F pool and from a new Ostracod natural gas discovery. We sold our 15.4% working interest in the 39 mmcf/d Bigoray Gas Plant for $4.2 million and entered into an agreement to receive preferential long-term processing fees that were 17% lower than the processing fees charged to other companies processing gas at the plant. We have retained a 100% interest in an crude oil battery and compressor station. At Bigoray, we completed the expansion of its fluid handling capability, increasing this capability to 25,000 bbls/d from 6,000 bbls/d. The west-central Alberta area provides us with excellent development drilling opportunities and adds an important balance to our portfolio of exploration areas. We are pursuing significant additional exploration and exploitation activities in our working interests in another 351,734 gross (135,390 net) acres of land, with an overall working interest of 38%, in other parts of central Alberta, including Halkirk, Garrington and Gilby to the south and east of Bigoray. PEACE RIVER ARCH, NORTH-CENTRAL ALBERTA We have working interests in 155,840 gross (95,918 net) acres of land approximately 20 to 30 kilometres north of Grande Prairie, as of June 30, 2002 with a 62% working interest. At Cecil, we own various working interests in 39,040 gross (18,881 net) acres of land, with a 48% average working interest in the aggregate. Production from the property is primarily crude oil and natural gas from the Cecil Charlie Lake "A", "L & M", "R" and "S" pools. Kiskatinaw crude oil production also became important in 2001. We own a 40% working interest and a 83% working interest in two central crude oil batteries and a 40% working interest in a solution gas plant servicing production at South Cecil. We also own a 40% working interest in a central battery at North Cecil and we own working interests ranging from 13.9% to 19.5% in the various functional units of the North Cecil Gas Plant. This third party operated natural gas plant was placed on stream in April 1998 and is currently capable of processing 50 mmcf/d. At Worsley, we own working interests in 8,640 gross (7,093 net) acres of land, a 82% working interest, primarily prospective for crude oil and natural gas from the Charlie Lake formation. We also own a 95.3% working interest in a 4 mmcf/d solution gas plant and an 80% working interest in an crude oil battery. At Clayhurst, natural gas production is obtained from four Compton operated wells. Natural gas is delivered through a 11.4 kilometre sales line which is 100% owned by us and which provides us with strategic control over a large region that is geographically isolated by river gorges. Our land position consisting of 18,080 gross (12,544 net) acres at an average working interest of 69% of undrilled land in this area is proximate to a natural gas gathering system and processing facility which is leased by us. An amine unit was installed in 2000 to allow for sour gas production. In the Progress, Saddlehills, Sexsmith and Howard areas, we hold a 21.7% working interest in the Progress Halfway Unit, which contains 14 producing natural gas wells. Production in the area also occurs from the Doe Creek, Bluesky, Gething, Cadomin, Charlie Lake and Montney formations. We have a 4.96% working interest in the 147 mmcf/d Progress Gas Plant and a 4.4% working interest in the 31 mmcf/d Teepee Creek Gas Plant, both of which are located in this area. The Peace River Arch area is highly competitive and offers multizone potential for both exploration and development opportunities. Specifically, we believe that our Cecil and Worsley crude oil properties offer excellent development opportunities, while our Clayhurst and area natural gas property has multizone exploration potential. WEST RAINBOW AND ZAMA, NORTHERN ALBERTA/BRITISH COLUMBIA We own working interests in 137,775 gross (101,653 net) acres of land in the West Rainbow and Zama areas of northern Alberta and British Columbia, as of June 30, 2002, with a 74% working interest. -40- We acquired the exploration lands in West Rainbow to find and develop natural gas reserves in an area characterized by multiple potential reservoirs, including the Cretaceous Bluesky, Mississippian zones and the Devonian, Jean Marie, Sulphur Point, Slave Point and Keg River formations. We also have production and exploitation opportunities on our lands to the north at Zama. OTHER UNDEVELOPED LAND In addition to our four core areas discussed above, we have 5% of our net undeveloped land in minor properties outside of our four geographic core areas. These lands are located in northeastern British Columbia, northeastern Saskatchewan and southern Manitoba. These minor properties were acquired primarily as a result of acquisitions of corporations whose primary assets were in one or more of our core areas. Currently, less than 1% of our production comes from these minor properties. RESERVES SUMMARY Reserve calculations involve the estimate of future net recoverable reserves of crude oil, natural gas liquids and natural gas and the timing and amount of future net revenue to be received therefrom. Such estimates are not precise and are based on assumptions regarding a variety of factors, many of which are variable and uncertain. See "Risk Factors -- Risks Related to our Business". The following table summarizes our undeveloped land and our natural gas, crude oil and natural gas liquids reserves as at the dates indicated and the present value attributable to the reserves as of those dates, discounted at 10%. The reserve information as of December 31, 2001 was prepared by Outtrim Szabo Associates Ltd. The reserve information as of December 31, 1999 and 2000 was prepared by or reviewed by Outtrim Szabo Associates Ltd. In connection with Outtrim Szabo Associates Ltd.'s reserve evaluation, we provided them with land data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, capital budget forecasts, financial data and future operating plans. Outtrim also obtained other engineering, geological or economic data required by them from public records, other operators and their non-confidential files. Outtrim did not independently verify the factual information that we provided to them or that they obtained from other sources and did not conduct a field inspection.
HISTORICAL ------------------------------------------ AS OF DECEMBER 31, ------------------------------------------ 1999 2000 2001 ------------ ------------ ------------ PROVED RESERVES: Natural gas (mmcf).................. 181,759 223,761 262,448 Crude oil & natural gas liquids (mbbls) 10,682 9,423 9,777 Natural gas equivalent (mmcfe).... 245,851 280,302 321,110 % natural gas..................... 74% 80% 82% % proved developed................ 85% 85% 89% Estimated reserve life (in years)(1) 8.9 7.9 8.2 Annual reserve replacement ratio(2). 268% 197% 204% Recycle ratio(3).................... 1.2x 2.2x 1.5x PV-10 (thousands of dollars)(4)..... $ 393,448 $ 1,227,443 $ 465,619 Standardized measure of discounted future net cash flows (thousands in dollars)............................ $ 271,486 $ 709,869 $ 317,461 UNDEVELOPED LAND Gross undeveloped land (thousands of acres)............................ 707 808 962 Working interest percentage......... 71% 76% 73%
---------- (1) Reserve life is calculated by dividing our proved reserves at year end by our annual production in that year. (2) The annual reserve replacement ratio is a percentage determined by dividing our estimated proved reserves added during a year from exploitation, development and exploration activities, acquisition of proved reserves and revisions of previous estimates, excluding property sales, by our annual production in that year. (3) The recycle ratio is a multiple determined by dividing our netback per boe by our finding and development costs per boe in that year. Netback per boe is calculated by dividing our annual net revenues generated from producing oil and natural gas volumes, net of operating costs and administrative -41- expenses by our annual production in that year. Finding and development costs per boe is calculated by dividing our estimated finding and development costs associated with our estimated proved reserves added during the year by our estimated proved reserves added in that year from exploitation, development and exploration activities, acquisition of proved reserves and revisions of previous estimates, excluding property sales. (4) PV-10 is the present value of our estimated future net cash flows before income taxes, discounted at 10% per year, calculated using constant pricing. The prices used in 1999 were $2.88 per mcf of natural gas, $36.64 per barrel of crude oil and $30.88 per barrel of natural gas liquids. The prices used in 2000 were $9.69 per mcf of natural gas, $39.33 per barrel of crude oil and $37.57 per barrel of natural gas liquids. The prices used in 2001 were $3.68 per mcf of natural gas, $32.63 per barrel of crude oil and $22.98 per barrel of natural gas liquids. PV-10 is not necessarily indicative of actual future cash flows. STANDARDIZED MEASURE The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proven Oil and Natural Gas Reserves (the "Standardized Measure") does not purport to present the fair market value of our crude oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of crude oil and natural gas, the probability of recoveries in excess of existing proved reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates or reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revisions. Under the Standardized Measure, future cash inflows were estimated by applying year-end prices, adjusted for contracts currently in place to deliver production to the estimated future production of year-end proved reserves. Future cash inflows were reduced by estimated future production and development costs, based on year-end costs, to determine pre-tax cash inflows. Future taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated proved crude oil and natural gas properties. Tax credits and net operating loss carry forwards were also considered in the future income tax calculation. The following table shows the present value of our estimated future cash flow, after income taxes, from our proved crude oil and natural gas reserves, discounted at 10%, using constant pricing, as calculated by us in accordance with the SFAS 69 accounting standard: DECEMBER 31, ------------------------------------ 1999 2000 2001 --------- ---------- --------- (DOLLARS IN THOUSANDS) Standardized measure of discounted future net cash flows................ $ 271,486 $ 709,869 $ 317,461 PRODUCTION COSTS The following table shows our production costs for the periods indicated:
SIX MONTHS ENDED YEARS ENDED DECEMBER 31, JUNE 30, ------------------------------------- ------------------------- 1999 2000 2001 2001 2002 ---------- --------- ---------- ---------- ------------ Crude oil and natural gas liquids ($/bbl) 5.42 7.66 8.25 8.22 8.41 Natural gas ($/mcf).................... 0.68 0.72 0.89 0.86 0.93 Total ($/boe)...................... 4.45 5.32 6.13 6.01 6.29
DRILLING ACTIVITY The number of gross and net exploratory and development wells we drilled during the periods indicated is shown below: EXPLORATORY WELLS
GROSS NET -------------------------------------- ---------------------------------------- PRODUCTIVE NON-PRODUCTIVE TOTAL PRODUCTIVE NON-PRODUCTIVE TOTAL ------------ ----------- ------- ------------ ------------ ---------- 1999............................... 23 16 39 17.1 15.0 32.1 2000............................... 33 23 56 27.1 18.0 45.1 2001............................... 31 15 46 24.0 13.0 37.0 January 1 - June 30, 2002.......... 10 3 13 7.5 2.3 9.8
-42- DEVELOPMENT WELLS
GROSS NET -------------------------------------- ---------------------------------------- PRODUCTIVE NON-PRODUCTIVE TOTAL PRODUCTIVE NON-PRODUCTIVE TOTAL ------------ ----------- ------- ------------ ------------ ---------- 1999............................... 37 7 44 33.4 5.0 38.4 2000............................... 34 6 40 29.0 4.2 33.2 2001............................... 41 8 49 28.1 5.7 33.8 January 1 - June 30, 2002.......... 24 2 26 14.4 1.0 15.4
PRODUCTIVE WELLS The following table shows our gross and net interests in productive crude oil, natural gas and service wells as of June 30, 2002. Productive wells are producing wells and wells capable of production: GROSS NET --------- -------- Crude oil wells............ 470 173.2 Natural gas wells.......... 586 264.0 Service wells.............. - - --------- -------- Total.................. 1,056 437.2 ========= ======== LAND The following table provides information about the amount of developed and undeveloped land we owned as of June 30, 2002. GROSS NET --------- -------- Developed land (acres)..... 519,115 224,990 Undeveloped land (acres)... 826,591 635,371 --------- -------- Total.................. 1,345,706 860,361 ========= ======== MARKETING We sell our natural gas in a variety of markets to marketers, distributors and end users. Our natural gas production is sold under a combination of longer term contracts with aggregators and short term 30 day AECO indexed contracts. During 2001, approximately 40% of our natural gas production was sold to aggregators. In southern Alberta, a maximum 30 mmcf/d of natural gas production is committed to Pan-Alberta Gas Ltd., of which 7 mmcf/d is contracted until the year 2013 and 23 mmcf/d is contracted until September 2002. Production volumes in excess of 30 mmcf/d from lands now dedicated to Pan-Alberta Gas Ltd. are non-contracted. Additionally, production from certain lands in southern Alberta, currently producing approximately 7 mmcf/d, are contracted to TransCanada Gas Services Ltd. until the year 2012. Various other minor contracts with Pan-Alberta Gas Ltd. and TransCanada Gas Services Ltd. are for the life of the reserves from the lands dedicated. Crude oil and natural gas liquids are sold under various short term contracts which track the Edmonton par price. We sell crude oil and natural gas liquids primarily to refineries and marketers of crude oil and natural gas liquids. From time to time, we may enter into hedging arrangements to mitigate commodity price risk and take advantage of opportunistic pricing. In accordance with our policy, hedging programs will not exceed 50% of non-contracted production. SEISMIC We own rights to copy and utilize large seismic databases. The rights to utilize non-proprietary seismic databases have been obtained by us primarily through purchases of copies of such databases. The third parties who own the proprietary rights broker or sell database copies to other oil and gas industry players as well. We also own exclusive proprietary rights of seismic data, that we have shot and processed directly on lands within areas of interest. These databases include conventional two-dimensional seismic covering over 90,000 kilometres of land and three dimensional seismic data shot over -43- 2,200 square kilometres of land primarily in areas throughout Alberta. Additionally, we have rights to use 6,500 square kilometres of seismic covering areas in southern Manitoba. Our exploration team uses these large seismic databases in our exploration and acquisition decisions. COMPETITION The oil and natural gas industry is very competitive. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our competitive position depends on our geological, geophysical and engineering expertise, our financial resources, our ability to develop our properties and our ability to select, acquire and develop proved reserves. We compete with a substantial number of other companies which have larger technical staffs and greater financial and operational resources. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also conduct refining operations and market refined products. We also compete with other oil and natural gas companies and other industries supplying energy and fuel in the marketing and sale of oil and natural gas to transporters, distributors and end users, including industrial, commercial and individual consumers. We also compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time. Finally, companies not previously investing in oil and natural gas may choose to acquire reserves to establish a firm supply or simply as an investment. Such companies will also provide competition for us. REGULATION The oil and natural gas industry in Canada is subject to extensive controls and regulations imposed by various levels of government. We do not expect that any of these controls or regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size. Crude oil and natural gas located in Alberta is owned predominantly by the provincial government. The provincial government grants rights to explore for and produce oil and natural gas under leases, licenses and permits with terms generally varying from two years to five years and on conditions contained in provincial legislation. Leases, licenses and permits may be continued indefinitely by producing under the lease, license or permit. Some of the oil and natural gas located in Alberta is privately owned and rights to explore for and produce oil and natural gas are granted by the mineral owners on negotiated terms and conditions. In Canada, producers of oil negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. The price depends in part on oil quality, prices of competing fuels, distance to market and the value of refined products. Oil exports may be made under export contracts having terms not exceeding one year in the case of oil other than heavy oil, so long as an order approving any such export has been obtained from the National Energy Board. Any oil export to be made pursuant to a contract of longer duration requires an exporter to obtain an export licence from the National Energy Board and the issue of a license requires the approval of the Canadian federal government. The term of the license may not exceed 25 years. In Canada, the price of natural gas sold in interprovincial and international trade is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the Government of Canada through the National Energy Board. Producers and exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet criteria prescribed by the National Energy Board. Natural gas exports for a term of two years or less, or for 2 to 20 years in quantities not more than 30,000 cubic metres (1.1 million cubic feet) per day may be made under a National Energy Board order and exports for a longer duration or larger volumes may be made under a National Energy Board license and Canadian federal government approval. The Alberta provincial government also regulates the removal of natural gas from the province for consumption elsewhere. It does so based on such factors as reserve availability, transportation arrangements and market considerations. In addition to federal regulations, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of -44- oil and natural gas production. Royalties payable on production from lands other than government lands are determined by negotiations between the mineral owner and the lessee. Royalties on government land are determined by government regulation and are generally calculated as a percentage of the value of gross production, and the rate of royalties payable generally depends upon prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced. In general, royalty rates are sensitive to sales prices, as higher prices attract higher royalty rates. Similarly, higher productivity wells and wells producing a higher grade of crude oil and natural gas are subject to higher royalty rates. The complex royalty structure for oil and gas reserves in the province of Alberta is designed to provide permanent incentives for exploring and developing such reserves and includes the following policies: (i) the first wells drilled in new oil pools discovered on or after October 1, 1992 receive a permanent one year oil royalty holiday, subject to a $1,000,000 per well cap and a reduced royalty rate thereafter; (ii) the base royalty rates on pre-October 1, 1992 production of oil and gas is reduced; (iii) royalty holidays and reduced royalties apply to reactivated and low productivity wells, and to vertical oil wells which require horizontal re-entry; (iv) separate par pricing for light medium and heavy oil; and (v) a royalty formula which is sensitive to price fluctuations. Alberta's Third Tier Royalty applies to oil pools discovered after September 30, 1992 with a base rate of 10% and a rate cap of 25%. The new oil royalty reserved to the Alberta government has a base rate of 10% and a rate cap of 30% and for old oil a base rate of 10% and a rate cap of 35%. The royalty reserve to the Alberta government, subject to various incentives, is between 15% and 30%, in the case of new gas, and between 15% and 35%, in the case of old gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 continues to be eligible for a royalty exemption for a period of 12 months, or such later time that the value of the extended royalty quantity equals a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends upon the depth of the well. From time to time the governments of Canada and Alberta have established incentive programs which have included royalty rate deductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. In Alberta, a producer of oil or natural gas is entitled to a credit against certain royalties payable to the Alberta government by virtue of the Alberta Royalty Tax Credit Program. The Alberta Royalty Tax Credit Program is based on a price sensitive formula and ranges between 75%, for prices for oil at or below $100 per cubic metre, to 25%, for prices above $210 per cubic metre. In general, the Alberta Royalty Tax Credit rate is applied to a maximum of $2,000,000 of government royalties payable for each producer or associated group of producers. Government royalties on production from producing properties acquired from corporations claiming maximum entitlement to the Alberta Royalty Tax Credit will generally not be eligible for the Alberta Royalty Tax Credit. The rate is established quarterly based on the average "par price", as determined by the Alberta Department of Energy for the previous quarterly period. The "par price" is the gas reference price established by the Alberta Department of Energy for determining Alberta government gas royalties. It is essentially the weighted average price of both contractual and spot gas sold within the province of Alberta during the month adjusted to reflect intra-Alberta transportation, a marketing fee, and any pipeline loss. The impact of the Alberta Royalty Tax Credit on us in fiscal 2001 was $0.5 million. The North American Free Trade Agreement ("NAFTA") among the governments of Canada, the United States and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada-U.S. Free Trade Agreement. Subject to the General Agreement on Tariffs and Trade, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, so long as any export restrictions do not: o reduce the proportion of energy resources exported relative to total supply (based upon the proportion prevailing in the most recent 36 month period or another representative period agreed upon by the parties); -45- o impose an export price higher than the domestic price (subject to an exception that applies to some measures that only restrict the value of exports); or o disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, with some limited exceptions. ENVIRONMENTAL The oil and natural gas industry is governed by environmental regulation under Canadian federal and provincial laws, rules and regulations which restrict and prohibit the release or emission, and regulate the storage and transportation, of various substances produced or utilized in association with oil and natural gas industry operations. In addition, applicable environmental laws require that well and facility sites be abandoned and reclaimed, to the satisfaction of provincial authorities, in order to prevent pollution from former operations. Also, environmental laws may impose upon "responsible persons" remediation obligations on property designated as a contaminated site. Responsible persons include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any present or past owner, tenant or other person in possession of the site. A breach of environmental laws may result in the imposition of fines and penalties, and imprisonment for directors and officers, in addition to the costs of abandonment and reclamation. The primary environmental statute in Alberta is the ENVIRONMENTAL PROTECTION AND ENHANCEMENT Act. This Act is administered and enforced by Alberta Environment. Certain environmental aspects of the oil and natural gas industry are also regulated by the Alberta Energy & Utilities Board (the "EUB") under various statutes, regulations, guides and codes of practice. Both Alberta Environment and the EUB have significant powers and ranges of enforcement actions available to force compliance with environmental regulations. We have established guidelines and management systems to ensure compliance with environmental laws, rules and regulations. We have designated a compliance officer whose responsibility is to monitor regulatory requirements and their impact on us and to implement appropriate compliance procedures. We also employ an environmental manager whose responsibilities include ensuring that our operations are carried out in accordance with applicable environmental guidelines and implementing adequate safety precautions. The existence of these positions cannot, however, guarantee total compliance with environmental laws, rules and regulations. As part of our environmental management program, we are in the process of undertaking environmental remediation at a number of sites. We have budgeted approximately $665,000 for these efforts during 2002. The actions to be taken are in accordance with current regulatory requirements and are not the result of any governmental agency order or directive. EMPLOYEES As of June 30, 2002, we had 72 employees in our Calgary office and 25 employees at field locations. In addition, as of June 30, 2002, we employed 3 individuals on a full-time contract basis. None of our employees are represented by a union and we consider our relations with our employees to be good. LEGAL PROCEEDINGS We are a party to various legal actions in the ordinary course of business. In our opinion, none of these actions, either individually or in the aggregate, will have a material adverse effect on our financial condition or operating results. -46- MANAGEMENT The following table sets forth the name and position held of each of our directors and executive officers:
NAME OF DIRECTOR OR OFFICER AGE POSITION HELD ADDRESS ----------------------------- ------- ------------------------------- ------------------------ Mel F. Belich, Q.C......... 54 Director, Chairman Calgary, Alberta, Canada Irvine J. Koop, P. Eng.... 56 Director Calgary, Alberta, Canada Jeffrey T. Smith, P. Geol. 54 Director Calgary, Alberta, Canada John W. Preston............ 55 Director Calgary, Alberta, Canada Ernest G. Sapieha, C.A..... 51 Director, President and Calgary, Alberta, Canada Chief Executive Officer of the Corporation Norman G. Knecht, C.A...... 58 Vice-President, Finance and Calgary, Alberta, Canada Chief Financial Officer of the Corporation Murray J. Stodalka, P. Eng 41 Vice-President, Engineering Calgary, Alberta, Canada and Operations of the Corporation Kim N. Davies, P.Geoph..... 46 Vice-President, Exploration Calgary, Alberta, Canada of the Corporation Tim G. Millar, LLB......... 55 Corporate Secretary of the Calgary, Alberta, Canada Corporation
MEL F. BELICH, Q.C. has been one of our directors since 1993 and was appointed Chairman of our board of directors in 2001. Mr. Belich graduated from the University of Calgary in 1970 with a Bachelor of Arts degree. He obtained his law degree from the University of Dalhousie in 1974. In 1999, Mr. Belich completed the Harvard University Executive Management Program. Prior to 1994, Mr. Belich was a senior partner in the law firm of Milner Fenerty (now Fraser Milner Casgrain LLP), where he held a series of senior management and counsel positions during his 20 years with that firm. He was appointed Queen's Counsel in 1996. Mr. Belich is currently Group Vice President-- International, Enbridge Inc., a position he has held since September 1, 2000. He has also been Chairman of Enbridge International Inc. and Chairman of Enbridge Technology Inc. since May 1, 1999. Mr. Belich is also a director of numerous Enbridge affiliates, including Enbridge Pipelines (Athabasca) Inc., Enbridge Consumers Energy Inc., and Enbridge Services Inc. Prior to his current assignment, Mr. Belich was Senior Vice President responsible for Enbridge's International and Corporate Law groups. Mr. Belich is a member of the Institute of Americas, the Calgary, Alberta, Canadian and International Bar Associations, and is a member of a number of senior legal counsel associations, labour and transportation law associations in Canada and the United States. IRVINE J. KOOP, P. ENG. has been one of our directors since 1996. Mr. Koop graduated from the University of Manitoba in 1968 with a Bachelor of Science degree in mechanical engineering. He completed the Wharton Business School Program from the University of Pennsylvania in 1991. From November 1999 until his retirement in April 2001, Mr. Koop was Executive Vice-President and President and Chief Executive Officer, Pipelines and Midstream, Westcoast Energy Inc. (an energy products and services company). Prior thereto, from 1996 to 1999, he was President, Pipeline and Field Services Division of Westcoast Energy Inc. Prior to 1996, Mr. Koop has served in various engineering and senior management positions in several major resource and energy companies. Mr. Koop is also a director of NAL Energy (a conventional oil and gas company), and a director and past chair of the Canadian Energy Research Institute. Mr. Koop is a member of the Association of Petroleum Engineers, Geologists, Geophysicists of Alberta, and the Canadian Institute of Mining and Minerals. JEFFREY T. SMITH, P. GEOL. has been one of our directors since 1999. Mr. Smith graduated from the University of Ottawa in 1970 with a Bachelor of Science in Geology (with Honors). Mr. Smith has been an independent businessman since 1997. Before that time, Mr. Smith was Chief Operating Officer of Northstar Energy Corporation from 1995 to 1997. Prior thereto, Mr. Smith held numerous senior management positions with Northstar. Mr. Smith is an independent businessman and is currently a director of Seque Energy Corp. (a private crude oil and gas company), Rosetta Exploration (a public crude oil and gas exploration company), and Provident Energy Trust (a public crude oil and gas royalty trust) and Resolute Energy Corp. (a private crude oil and gas company). Mr. Smith is a member of the Association of Petroleum Engineers, Geologists, Geophysicists of Alberta, and the Canadian Society of Petroleum Geologists. JOHN W. PRESTON has been one of our directors since 1993. Mr. Preston graduated from Centennial College in Toronto, Ontario in 1969, with a business degree in marketing. Mr. Preston is an Account Executive with Sun Microsystems -47- of Canada Inc. (a computer company), a position he has held since 1992. Prior thereto, Mr. Preston held equivalent management positions at AT&T Canada, AES Data Inc. Canada and IBM Canada. ERNEST G. SAPIEHA, C.A. has been President and Chief Executive Officer of Compton since our incorporation in 1992. Mr. Sapieha has more than 20 years of experience in the petroleum industry. He graduated from the University of Saskatchewan in 1974 with a Bachelor of Commerce degree and received his Chartered Accountant designation in 1976. Since then, Mr. Sapieha has had a broad range of experience, serving in various senior positions with major accounting firms and large energy and resource companies with publicly trading shares. In 1986, Mr. Sapieha became a managing director of Petroleum Capital Corporation, a corporation involved in the formation, investment, financing and management of public crude oil and natural gas companies, drilling funds, and joint ventures, including Central Explorers Inc. and Triumph Energy Corporation. In 1992, Mr. Sapieha founded the Compton Resource Corporation 1992/1993 Oil and Gas Investment Fund. In 1993, Mr. Sapieha founded Compton Petroleum Corporation. NORMAN G. KNECHT, C.A. was appointed our Vice-President, Finance and Chief Financial Officer in 1997. Mr. Knecht has more than 25 years of experience in public accounting. Mr. Knecht graduated from the University of Alberta in 1969 with a Bachelor of Education degree and received his Chartered Accountant designation in 1972. Mr. Knecht worked and served as a partner in national accounting firms until 1982 when he joined Doane Raymond as a general audit partner. He continued in this capacity, primarily serving junior public corporations in the resource industries, until joining us in November 1997. MURRAY J. STODALKA, P.ENG. was appointed our Vice-President, Engineering and Operations in 1996. Mr. Stodalka has more than 19 years of experience in the crude oil and natural gas industry. He graduated from the University of Saskatchewan in 1982 with a Bachelor of Science degree in mechanical engineering and was subsequently employed in various senior engineering positions by major Canadian and United States resource companies. From 1993 to 1996, Mr. Stodalka was a Senior Production and Exploitation Engineer for Pennzoil Canada Inc. Mr. Stodalka joined us in 1996. KIM N. DAVIES, P. GEOPH. was appointed Vice-President, Exploration of Compton in 1996. Ms. Davies has more than 20 years of experience in the crude oil and natural gas industry. She graduated from the University of Calgary in 1980 with a Bachelor of Science degree in physics. Ms. Davies was employed from 1981 to 1992 in various geophysical positions by Petro-Canada, where she gained experience in both international and domestic exploration and development. For the period between 1993 to 1996, Ms. Davies was employed with Pennzoil Canada Inc. as Senior Geophysicist and value creation team leader. Ms. Davies joined us in 1996. TIM G. MILLAR, LLB. was appointed the Corporate Secretary of Compton in 1996. Mr. Millar graduated from the University of Alberta in 1967 with a Bachelor of Arts degree with a major in history and a minor in economics. Mr. Millar then received his law degree from the University of Alberta in 1970. Mr. Millar is a senior partner of the Fraser Milner Casgrain LLP law firm and is currently the manager of Fraser Milner Casgrain LLP's Commercial Practice Section. Mr. Millar has been with Fraser Milner Casgrain LLP (or its predecessors) since 1970. His expertise is in the commercial area of resources law and he practices principally in the area of oil and gas law, including matters involving acquisitions and dispositions of oil and gas assets. Mr. Millar currently serves as a director of Hallmark Tubulars Ltd. Mr. Millar is a member of the Law Society of Alberta, the Calgary Bar Association, the Natural Resources Subsection of the Canadian Bar Association and the Petroleum Joint Venture Association. COMPENSATION OF EXECUTIVE OFFICERS The following table sets forth the compensation for our Chief Executive Officer and each of our three other most highly compensated officers (measured by base salary and bonus) for the financial years ended December 31, 1999, 2000 and 2001.
LONG TERM COMPENSATION ANNUAL COMPENSATION AWARDS -------------------------------- ----------------------------- NAME AND PRINCIPAL POSITION YEAR SALARY BONUS SECURITIES UNDER OPTIONS GRANTED ($) ($) (#) -------------------------------- -------- ---------------- ------------ ------------------------------ Ernest G. Sapieha 2001 295,000 150,000 60,000 President and CEO 2000 225,000 80,000 100,000 1999 175,000 80,000 150,000
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LONG TERM COMPENSATION ANNUAL COMPENSATION AWARDS -------------------------------- ----------------------------- NAME AND PRINCIPAL POSITION YEAR SALARY BONUS SECURITIES UNDER OPTIONS GRANTED ($) ($) (#) -------------------------------- -------- ---------------- ------------ ------------------------------ Norman G. Knecht 2001 195,000 95,000 30,000 Vice-President, Finance and 2000 170,000 50,000 50,000 Chief Financial Officer 1999 140,000 50,000 50,000 Murray J. Stodalka 2001 195,000 95,000 30,000 Vice-President, 2000 170,000 50,000 50,000 Engineering and Operations 1999 140,000 50,000 50,000 Kim N. Davies 2001 185,000 85,000 30,000 Vice-President, Exploration 2000 160,000 40,000 50,000 1999 140,000 50,000 50,000
COMPENSATION OF DIRECTORS During the 2001 fiscal year, each of our directors, excluding Ernest G. Sapieha who is also an officer of Compton, received an annual fee of $25,000 as compensation for acting as a director and attendance at board meetings. Additionally, each of the directors, excluding Ernest G. Sapieha received a fee of $1,000 per meeting for attendance at Board meetings to an aggregate annual maximum of $20,000. The Chairman of the Board of our Company receives an annual fee of $20,000 as compensation for acting as Chairman of the Board. Each chairman of the three committees of the board receives an additional annual fee of $7,500 as compensation for acting as the chairman of the committee. Additionally, each of the directors, excluding Ernest G. Sapieha, received options during our 2001 fiscal year to acquire 25,000 common shares at $3.83 per share as compensation for acting as a director. STOCK OPTION PLAN Our stock option plan provides that options will be granted to our directors, officers, employees and consultants and for such number of common shares as the board determines in its discretion, at an exercise price equal to the closing price of the common shares on the TSE on the trading day immediately preceding the date on which the option is granted. The board may determine the manner, time and rate of exercise of an option. Options granted under the stock option plan, subject to limited exceptions, must be exercised while the optionee remains employed as a director, officer, employee or consultant. The options are not transferable or assignable. The number of options granted reflects competitive practice and is based on the market value of the common shares on the date of the grant. As of June 30, 2002, there were 14,500,000 common shares reserved for issuance under the plan. As of June 30, 2002, there were options outstanding to purchase 9,910,954 common shares. The total number of common shares reserved for issuance to any one person under the plan must not exceed 5% of our outstanding common shares on a non-diluted basis. Furthermore, the aggregate number of common shares reserved for issuance under options granted to our directors, officers, 10% shareholders and each of their affiliates and associates, may not exceed 10% of our outstanding common shares (on a non-diluted basis). The issuance of common shares to our directors, officers, 10% shareholders and each of their affiliates and associates under the plan and any other share compensation arrangements, within a one year period, may not exceed 10% of our outstanding common shares (on a non-diluted basis), and the issuance of common shares to any one officer, director, 10% shareholder or their affiliates and associates under the plan and any other share compensation arrangements, within a one year period, may not exceed 5% of our outstanding common shares (on a non-diluted basis). OPTION GRANTS DURING THE MOST RECENTLY COMPLETED FINANCIAL YEAR The following table sets forth the options granted to our directors, the Chief Executive Officer and our three other most highly compensated officers for our most recently completed fiscal year. -49-
MARKET VALUE OF SECURITY % OF TOTAL UNDERLYING OPTIONS OPTIONS EXERCISE OPTIONS ON DATE GRANTED(1) GRANTED DURING PRICE OF GRANT NAME (#) YEAR ($/SECURITY) ($/SECURITY) EXPIRY DATE --------------------- ------------ ---------------- ------------ ------------------ ----------------- Mel F. Belich....... 25,000 0.6 3.83 3.83 July 23, 2011 Irvine J. Koop...... 25,000 0.6 3.83 3.83 July 23, 2011 John W. Preston..... 25,000 0.6 3.83 3.83 July 23, 2011 Jeffrey T. Smith.... 25,000 0.6 3.83 3.83 July 23, 2011 Ernest G. Sapieha... 60,000 1.6 3.83 3.83 July 23, 2011 Norman G. Knecht.... 30,000 0.8 3.83 3.83 July 23, 2011 Murray J. Stodalka.. 30,000 0.8 3.83 3.83 July 23, 2011 Kim N. Davies....... 30,000 0.8 3.83 3.83 July 23, 2011
---------- (1) All securities under option are common shares. AGGREGATED OPTION EXERCISES DURING THE MOST RECENTLY COMPLETED FINANCIAL YEAR AND FINANCIAL YEAR-END OPTION VALUES The following table sets forth details of all options exercised by our Chief Executive Officer and our three other most highly compensated officers in our most recently completed financial year. The table also details, as at December 31, 2001, the number of exercisable and unexercisable options that were unexercised and also the value of such options where they were in-the-money.
VALUE OF UNEXERCISED UNEXERCISED OPTIONS AT IN-THE-MONEY OPTIONS AT SECURITIES AGGREGATE FY-END FY-END ACQUIRED VALUE (#) ($) ON EXERCISE REALIZED ------------------------------ ----------------------------- NAME (#) ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE -------------------------- ------------ ------------ ------------ -------------- ----------- -------------- Ernest G. Sapieha.... -- -- 1,218,333 126,667 4,099,417 164,533 Norman G. Knecht..... -- -- 650,000 80,000 1,880,667 113,933 Murray J. Stodalka... -- -- 650,000 80,000 2,205,667 113,933 Kim N. Davies........ -- -- 650,000 80,000 2,165,667 113,933
As at December 31, 2001, the closing price of our common shares on the TSE was $4.20 per share. EMPLOYMENT CONTRACTS As at December 31, 2001, we had entered into employment contracts with each of our four executive officers. The contracts provide for compensation to the executives for loss of office in the event of change of control of Compton, as defined in those contracts. Such compensation is the aggregate of twice the executive's current salary and benefits and twice the amount of the executive's last bonus, if any. Our stock option plan provides that in the event an executive ceases to be employed by us, for any reason (excluding termination for cause, death or disability) the executive can exercise their options within 30 days of such termination. In the event of termination for cause, the executive's options expire immediately upon delivery of the notice of termination. In the event of disability or death, an executive's options expire one year after cessation of employment. RELATED PARTY TRANSACTIONS Murray J. Stodalka, our Vice-President, Engineering and Operations, is currently indebted to us in the amount of $150,000 arising from an interest-free loan made to him in 1996 for the purpose of purchasing 300,000 common shares. The loan is repayable on demand or on the date on which he ceases to be employed by us, whichever is earlier. Mr. Stodalka has pledged the shares acquired with the loan as security for the indebtedness and we have agreed that his liability in respect of the loans will be limited to the pledged shares. The amount outstanding with respect to this loan on September 1, 2002 was $150,000. -50- SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT The following table contains information provided to us by our shareholders, or contained in our share ownership records, with respect to beneficial ownership of our common shares as of September 1, 2002: o each named executive officer; o each director; and o all directors and executive officers as a group. Each person has sole voting and investment power with respect to the shares listed. SHARES BENEFICIALLY OWNED ------------------------- NAME NUMBER % ----------------------------------------------- ------------ --------- Mel F. Belich, Q.C........................ 1,814,616 1.60 Irvine J. Koop, P. Eng................... 459,000 0.40 John W. Preston........................... 2,030,246 1.80 Ernest G. Sapieha, C.A.................... 6,684,861 5.90 Jeffrey T. Smith, P. Geol................ 36,000 0.03 Norman G. Knecht, C.A..................... 39,850 0.03 Murray J. Stodalka, P. Eng............... 391,068 0.34 Kim N. Davies, P.Geoph.................... 252,726 0.22 ------------ --------- All directors and executive officers as a group (8 persons)...................... 11,708,367 10.32 ============ ========= PRINCIPAL SHAREHOLDERS To our knowledge, the only persons who beneficially own, directly or indirectly, or exercise control or direction over more than 5% of our issued and outstanding common shares are Centennial Energy Partners L.L.C. of 900 Third Avenue, New York, New York, U.S.A., which itself and through Centennial Energy Partners, L.P., Tercentennial Energy Partners L.P., Quadrennial Partners L.P., Xandu Partners and Pumpkin Foundation owns 11,795,400 Common Shares, representing approximately 10.40% of our outstanding common shares and Ernest G. Sapieha, who owns 5.90% of our outstanding common shares. STOCK OPTION GRANTS TO DIRECTORS The following table provides information relating to stock options held by our directors as of June 30, 2002.
NUMBER OF COMMON SHARES UNDERLYING EXERCISE NAME OPTIONS GRANTED DATE OF GRANT PRICE EXPIRATION DATE ---------------------- ----------------- ----------------------- ----------- ------------------- Mel F. Belich..... 500,000 September 13, 1996 $0.60 September 13, 2006 35,000 September 28, 1998 1.45 September 28, 2008 50,000 June 29, 1999 1.83 June 29, 2009 50,000 August 22, 2000 2.30 August 22, 2010 25,000 July 23, 2001 3.83 July 23, 2011 25,000 June 4, 2002 4.10 June 4, 2012 Irvine J. Koop.... 450,000 January 6, 1997 $0.80 January 6, 2007 35,000 September 28, 1998 1.45 September 28, 2008 50,000 June 29, 1999 1.83 June 29, 2009 50,000 August 22, 2000 2.30 August 22, 2010 25,000 July 23, 2001 3.83 July 23, 2011 25,000 June 4, 2002 4.10 June 4, 2012 Jeffrey T. Smith.. 200,000 June 29, 1999 $1.83 June 29, 2009 50,000 August 22, 2000 2.30 August 22, 2010 25,000 July 23, 2001 3.83 July 23, 2011 25,000 June 4, 2002 4.10 June 4, 2012
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NUMBER OF COMMON SHARES UNDERLYING EXERCISE NAME OPTIONS GRANTED DATE OF GRANT PRICE EXPIRATION DATE ---------------------- ----------------- ----------------------- ----------- ------------------- John W. Preston... 500,000 September 13, 1996 $0.60 September 13, 2006 35,000 September 28, 1998 1.45 September 28, 2008 50,000 June 29, 1999 1.83 June 29, 2009 50,000 August 22, 2000 2.30 August 22, 2010 25,000 July 23, 2001 3.83 July 23, 2011 25,000 June 4, 2002 4.10 June 4, 2012 Ernest G. Sapieha. 1,000,000 September 13, 1996 $0.60 September 13, 2006 35,000 September 28, 1998 1.45 September 28, 2008 50,000 June 29, 1999 1.83 June 29, 2009 100,000 June 29, 1999 1.83 June 29, 2009 50,000 August 22, 2000 2.30 August 22, 2010 50,000 August 22, 2000 2.30 August 22, 2010 60,000 July 23, 2001 3.83 July 23, 2011 60,000 June 4, 2002 4.10 June 4, 2012
DESCRIPTION OF OTHER INDEBTEDNESS SENIOR CREDIT FACILITIES PRODUCTION FACILITY. We currently have a $158.0 million extendible revolving credit facility with a Canadian chartered bank, as administrative agent and arranger, and a syndicate of lenders. The production facility is available for general corporate purposes. The revolving period may be extended by the lenders on a year to year basis and, if not otherwise extended, the production facility will mature on July 9, 2003 at which time this facility must be repaid in full. WORKING CAPITAL FACILITY. We currently have a $10 million extendible revolving working capital facility with a Canadian chartered bank. The working capital facility is available for ongoing working capital purposes. The revolving period may be extended by the lender on a year to year basis and, if not otherwise extended, the working capital facility will mature on July 9, 2003, at which time this facility must be repaid in full. As of June 30, 2002, we had no outstanding borrowings under this facility. Under our senior credit facilities, the amount of our permitted borrowing base was initially established by and is periodically redetermined by the lenders. Upon completion of the initial offering, we repaid substantially all amounts outstanding under our senior credit facilities, the total commitments available under these facilities was reduced and approximately $168.0 million is currently available for additional borrowings under these facilities, subject to the conditions contained therein. Permitted borrowings under our senior credit facilities are not to exceed the amount of our net borrowing base which is based upon our borrowing base less a deduction on account of debt service on the notes. Amounts outstanding under our senior credit facilities will bear interest at a rate dependent on the type of accommodation provided, including prime rate or U.S. base rate loans, bankers' acceptances or LIBOR loans, plus a margin based on our ratio of total consolidated debt to cash flow, that is currently set at 0.625%, 1.625% and 1.625%, respectively. Our senior credit facilities have customary covenants including, but not limited to, covenants with respect to: o creating additional liens or security interests; o transferring or selling of assets; o entering into mergers and amalgamations; o incurring additional debt; o providing additional guarantees; and -52- o entering into swaps and derivatives contracts. Our senior credit facilities are secured by a fixed and floating charge and security interest over all of our undertakings, properties and assets and by a pledge of all shares we hold in 867791 Alberta Ltd. and Hornet Energy Ltd., and are guaranteed by each of our borrowing base subsidiaries and 899776 Alberta Ltd. As of the date of this prospectus, our borrowing base subsidiaries are 867791 Alberta Ltd., Compton Petroleum and Hornet Energy Ltd. The guarantees are secured by a fixed and floating charge and security interest on all of the undertakings, properties and assets of each of our borrowing base subsidiaries and a floating charge and security interest on all of the undertakings, properties and assets of 899776 Alberta Ltd. Under the terms of our senior credit facilities, if we experience a change of control, the lenders may elect to terminate their commitments and our ability to request additional funding, and the lenders may declare all amounts outstanding to be immediately due and payable. Unless the lenders under the senior credit facilities agree to waive their rights to be immediately repaid, we will be obligated to immediately repay all principal then outstanding, and all accrued and unpaid interest and fees, if any, under the senior credit facilities. The foregoing is a summary of the material provisions of our senior credit facilities. It does not restate the agreements in their entirety. We urge you to read the credit agreements, because they, and not this description, set forth the full terms of the senior credit facilities. The credit agreements were filed as exhibits to our Registration Statement, of which this prospectus forms a part. See "Where You Can Find More Information". THE EXCHANGE OFFER TERMS OF THE EXCHANGE OFFER We are offering to exchange our exchange notes for a like aggregate principal amount of our initial notes. The exchange notes that we propose to issue in this exchange offer will be substantially identical to our initial notes except that, unlike our initial notes, the exchange notes will have no transfer restrictions or registration rights. You should read the description of the exchange notes in the section in this prospectus entitled "Description of the Exchange Notes". We reserve the right in our sole discretion to purchase or make offers for any initial notes that remain outstanding following the expiration or termination of this exchange offer and, to the extent permitted by applicable law, to purchase initial notes in the open market or privately negotiated transactions, one or more additional tender or exchange offers or otherwise. The terms and prices of these purchases or offers could differ significantly from the terms of this exchange offer. In addition, nothing in this exchange offer will prevent us from exercising our right to discharge our obligations on the initial notes by depositing certain securities with the trustee and otherwise. EXPIRATION DATE; EXTENSIONS; AMENDMENTS; TERMINATION This exchange offer will expire at 5:00 p.m., New York City time, on , 2002, unless we extend it in our reasonable discretion. The expiration date of this exchange offer will be at least 20 business days after the commencement of the exchange offer in accordance with Rule 14e-l(a) under the SECURITIES EXCHANGE ACT OF 1934 (the "Exchange Act"). We expressly reserve the right to delay acceptance of any initial notes, extend or terminate this exchange offer and not accept any initial notes that we have not previously accepted if any of the conditions described below under "--Conditions to the Exchange Offer" have not been satisfied or waived by us. We will notify the exchange agent of any extension by oral notice promptly confirmed in writing or by written notice. We will also notify the holders of the initial notes by mailing an announcement or by a press release or other public announcement before 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date unless applicable laws require us to do otherwise. -53- We also expressly reserve the right to amend the terms of this exchange offer in any manner. If we make any material change, we will promptly disclose this change in a manner reasonably calculated to inform the holders of our initial notes of the change including providing public announcement or giving oral or written notice to these holders. A material change in the terms of this exchange offer could include a change in the timing of the exchange offer, a change in the exchange agent and other similar changes in the terms of this exchange offer. If we make any material change to this exchange offer, we will disclose this change by means of a post-effective amendment to the registration statement which includes this prospectus and will distribute an amended or supplemented prospectus to each registered holder of initial notes. In addition, we will extend this exchange offer for an additional five to ten business days as required by the Exchange Act, depending on the significance of the amendment, if the exchange offer would otherwise expire during that period. We will promptly notify the exchange agent by oral notice, promptly confirmed in writing, or written notice of any delay in acceptance, extension, termination or amendment of this exchange offer. PROCEDURES FOR TENDERING INITIAL NOTES PROPER EXECUTION AND DELIVERY OF LETTERS OF TRANSMITTAL To tender your initial notes in this exchange offer, you must use one of the three alternative procedures described below: (1) BOOK-ENTRY DELIVERY PROCEDURE: Send a timely confirmation of a book-entry transfer of your initial notes, if this procedure is available, into the exchange agent's account at The Depository Trust Company in accordance with the procedures for book-entry transfer described under "-- Book-Entry Delivery Procedure" below, on or before 5:00 p.m., New York City time, on the expiration date. (2) REGULAR DELIVERY PROCEDURE: Complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal. Have the signatures on the letter of transmittal guaranteed if required by the letter of transmittal. Mail or otherwise deliver the letter of transmittal or the facsimile together with the certificates representing the initial notes being tendered and any other required documents to the exchange agent on or before 5:00 p.m., New York City time, on the expiration date. (3) GUARANTEED DELIVERY PROCEDURE: If time will not permit you to complete your tender by using the procedures described in (1) or (2) above before the expiration date and this procedure is available, comply with the guaranteed delivery procedures described under "--Guaranteed Delivery Procedure" below. The method of delivery of the initial notes, the letter of transmittal and all other required documents is at your election and risk. Instead of delivery by mail, we recommend that you use an overnight or hand-delivery service. If you choose the mail, we recommend that you use registered mail, properly insured, with return receipt requested. IN ALL CASES, YOU SHOULD ALLOW SUFFICIENT TIME TO ASSURE TIMELY DELIVERY. You should not send any letters of transmittal or initial notes to us. You must deliver all documents to the exchange agent at its address provided below. You may also request your broker, dealer, commercial bank, trust company or nominee to tender your initial notes on your behalf. Only a holder of initial notes may tender initial notes in this exchange offer. A holder is any person in whose name initial notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder. If you are the beneficial owner of initial notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your notes, you must contact that registered holder promptly and instruct that registered holder to tender your notes on your behalf. If you wish to tender your initial notes on your own behalf, you must, before completing and executing the letter of transmittal and delivering your initial notes, either make appropriate arrangements to register the ownership of these notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time. You must have any signatures on a letter of transmittal or a notice of withdrawal guaranteed by: -54- (1) a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc.; (2) a commercial bank or trust company having an office or correspondent in the United States; or (3) an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act, UNLESS the initial notes are tendered: (a) by a registered holder or by a participant in The Depository Trust Company whose name appears on a security position listing as the owner, who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the letter of transmittal and only if the exchange notes are being issued directly to this registered holder or deposited into this participant's account at The Depository Trust Company; or (b) for the account of a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States or an eligible guarantor institution within the meaning of Rule l7Ad-l5 under the Exchange Act. If the letter of transmittal or any bond powers are signed by: (1) the recordholder(s) of the initial notes tendered: the signature must correspond with the name(s) written on the face of the initial notes without alteration, enlargement or any change whatsoever. (2) a participant in The Depository Trust Company: the signature must correspond with the name as it appears on the security position listing as the holder of the initial notes. (3) a person other than the registered holder of any initial notes: these initial notes must be endorsed or accompanied by bond powers and a proxy that authorize this person to tender the initial notes on behalf of the registered holder, in satisfactory form to us as determined in our sole discretion, in each case, as the name of the registered holder or holders appears on the initial notes. (4) trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity: these persons should so indicate when signing. Unless waived by us, evidence satisfactory to us of their authority to so act must also be submitted with the letter of transmittal. To effectively tender notes through The Depository Trust Company, the financial institution that is a participant in The Depository Trust Company will electronically transmit its acceptance through the Automatic Tender Offer Program. The Depository Trust Company will then edit and verify the acceptance and send an agent's message to the exchange agent for its acceptance. An agent's message is a message transmitted by The Depository Trust Company to the exchange agent stating that The Depository Trust Company has received an express acknowledgment from the participant in The Depository Trust Company tendering the notes that this participant has received and agrees to be bound by the terms of the letter of transmittal, and that we may enforce this agreement against this participant. BOOK-ENTRY DELIVERY PROCEDURE Any financial institution that is a participant in The Depository Trust Company's systems may make book-entry deliveries of initial notes by causing The Depository Trust Company to transfer these initial notes into the exchange agent's account at The Depository Trust Company in accordance with The Depository Trust Company's procedures for transfer. To effectively tender notes through The Depository Trust Company, the financial institution that is a participant in The Depository Trust Company will electronically transmit its acceptance through the Automatic Tender Offer Program. The Depository Trust Company will then edit and verify the acceptance and send an agent's message to the exchange agent for its acceptance. An agent's message is a message transmitted by The Depository Trust Company to the exchange agent stating that The Depository Trust Company has received an express acknowledgment from the participant in The Depository Trust Company tendering the initial notes that this participation has received and agrees to be bound by the terms of the letter of -55- transmittal, and that we may enforce this agreement against this participant. The exchange agent will make a request to establish an account for the initial notes at The Depository Trust Company for purposes of the exchange offer within two business days after the date of this prospectus. A delivery of initial notes through a book-entry transfer into the exchange agent's account at The Depository Trust Company will only be effective if an agent's message or the letter of transmittal or a facsimile of the letter of transmittal with any required signature guarantees and any other required documents is transmitted to and received by the exchange agent at the address indicated below under "-- Exchange Agent" on or before the expiration date unless the guaranteed delivery procedures described below are complied with. DELIVERY OF DOCUMENTS TO THE DEPOSITORY TRUST COMPANY DOES NOT CONSTITUTE DELIVERY TO THE EXCHANGE AGENT. GUARANTEED DELIVERY PROCEDURE If you are a registered holder of initial notes and desire to tender your notes, and (1) these notes are not immediately available, (2) time will not permit your notes or other required documents to reach the exchange agent before the expiration date or (3) the procedures for book-entry transfer cannot be completed on a timely basis and an agent's message delivered, you may still tender in this exchange offer if: (1) you tender through a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States, or an eligible guarantor institution within the meaning of Rule 17Ad-15 under the Exchange Act; (2) on or before the expiration date, the exchange agent receives a properly completed and duly executed letter of transmittal or facsimile of the letter of transmittal, and a notice of guaranteed delivery, substantially in the form provided by us, with your name and address as holder of the initial notes and the amount of notes tendered, stating that the tender is being made by that letter and notice and guaranteeing that within three New York Stock Exchange trading days after the expiration date the certificates for all the initial notes tendered, in proper form for transfer, or a book-entry confirmation with an agent's message, as the case may be, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and (3) the certificates for all your tendered initial notes in proper form for transfer or a book-entry confirmation as the case may be, and all other documents required by the letter of transmittal are received by the exchange agent within three New York Stock Exchange trading days after the expiration date. ACCEPTANCE OF INITIAL NOTES FOR EXCHANGE; DELIVERY OF EXCHANGE NOTES Your tender of initial notes will constitute an agreement between you and us governed by the terms and conditions provided in this prospectus and in the related letter of transmittal. We will be deemed to have received your tender as of the date when your duly signed letter of transmittal accompanied by your initial notes tendered, or a timely confirmation of a book-entry transfer of these notes into the exchange agent's account at The Depository Trust Company with an agent's message, or a notice of guaranteed delivery from an eligible institution is received by the exchange agent. All questions as to the validity, form, eligibility, including time of receipt, acceptance and withdrawal of tenders will be determined by us in our sole discretion. Our determination will be final and binding. We reserve the absolute right to reject any and all initial notes not properly tendered or any initial notes which, if accepted, would, in our opinion or our counsel's opinion, be unlawful. We also reserve the absolute right to waive any conditions of this exchange offer or irregularities or defects in tender as to particular notes. Our interpretation of the terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of initial notes must be cured within such time as we shall determine. We, the exchange agent or any other person will be under no duty to give notification of defects or -56- irregularities with respect to tenders of initial notes. We and the exchange agent or any other person will incur no liability for any failure to give notification of these defects or irregularities. Tenders of initial notes will not be deemed to have been made until such irregularities have been cured or waived. The exchange agent will return without cost to their holders any initial notes that are not properly tendered and as to which the defects or irregularities have not been cured or waived as promptly as practicable following the expiration date. If all the conditions to the exchange offer are satisfied or waived on the expiration date, we will accept all initial notes properly tendered and will issue the exchange notes promptly thereafter. Please refer to the section of this prospectus entitled "-- Conditions to the Exchange Offer" below. For purposes of this exchange offer, initial notes will be deemed to have been accepted as validly tendered for exchange when, as and if we give oral or written notice of acceptance to the exchange agent. We will issue the exchange notes in exchange for the initial notes tendered pursuant to a notice of guaranteed delivery by an eligible institution only against delivery to the exchange agent of the letter of transmittal, the tendered initial notes and any other required documents, or the receipt by the exchange agent of a timely confirmation of a book-entry transfer of initial notes into the exchange agent's account at The Depository Trust Company with an agent's message, in each case, in form satisfactory to us and the exchange agent. If any tendered initial notes are not accepted for any reason provided by the terms and conditions of this exchange offer or if initial notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged initial notes will be returned without expense to the tendering holder, or, in the case of initial notes tendered by book-entry transfer procedures described above, will be credited to an account maintained with the book-entry transfer facility, as promptly as practicable after withdrawal, rejection of tender or the expiration or termination of the exchange offer. By tendering into this exchange offer, you will irrevocably appoint our designees as your attorney-in-fact and proxy with full power of substitution and resubstitution to the full extent of your rights on the notes tendered. This proxy will be considered coupled with an interest in the tendered notes. This appointment will be effective only when, and to the extent that we accept your notes in this exchange offer. All prior proxies on these notes will then be revoked and you will not be entitled to give any subsequent proxy. Any proxy that you may give subsequently will not be deemed effective. Our designees will be empowered to exercise all voting and other rights of the holders as they may deem proper at any meeting of note holders or otherwise. The initial notes will be validly tendered only if we are able to exercise full voting rights on the notes, including voting at any meeting of the note holders, and full rights to consent to any action taken by the note holders. WITHDRAWAL OF TENDERS Except as otherwise provided in this prospectus, you may withdraw tenders of initial notes at any time before 5:00 p.m., New York City time, on the expiration date. For a withdrawal to be effective, you must send a written or facsimile transmission notice of withdrawal to the exchange agent before 5:00 p.m., New York City time, on the expiration date at the address provided below under "--Exchange Agent" and before acceptance of your tendered notes for exchange by us. Any notice of withdrawal must: (1) specify the name of the person having tendered the initial notes to be withdrawn; (2) identify the notes to be withdrawn, including, if applicable, the registration number or numbers and total principal amount of these notes; (3) be signed by the person having tendered the initial notes to be withdrawn in the same manner as the original signature on the letter of transmittal by which these notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer sufficient to permit the trustee for the initial notes to register the transfer of these notes into the name of the person having made the original tender and withdrawing the tender; -57- (4) specify the name in which any of these initial notes are to be registered, if this name is different from that of the person having tendered the initial notes to be withdrawn; and (5) if applicable because the initial notes have been tendered through the book-entry procedure, specify the name and number of the participant's account at The Depository Trust Company to be credited, if different than that of the person having tendered the initial notes to be withdrawn. We will determine all questions as to the validity, form and eligibility, including time of receipt, of all notices of withdrawal and our determination will be final and binding on all parties. Initial notes that are withdrawn will be deemed not to have been validly tendered for exchange in this exchange offer. The exchange agent will return without cost to their holders all initial notes that have been tendered for exchange and are not exchanged for any reason, as promptly as practicable after withdrawal, rejection of tender or expiration or termination of this exchange offer. You may retender properly withdrawn initial notes in this exchange offer by following one of the procedures described under "-- Procedures for Tendering Initial Notes" above at any time on or before the expiration date. CONDITIONS TO THE EXCHANGE OFFER We will complete this exchange offer only if: (1) there is no change in the laws and regulations which, in our judgment, would reasonably be expected to impair our ability to proceed with this exchange offer; (2) there is no change in the current interpretation of the staff of the Commission which permits resales of the exchange notes; (3) there is no stop order issued by the Commission or any state securities authority suspending the effectiveness of the registration statement which includes this prospectus or the qualification of the indenture for our exchange notes under the TRUST INDENTURE ACT OF 1939 and there are no proceedings initiated or, to our knowledge, threatened for that purpose; (4) there is no action or proceeding instituted or threatened in any court or before any governmental agency or body that in our judgment would reasonably be expected to prohibit, prevent or otherwise impair our ability to proceed with this exchange offer; and (5) we obtain all governmental approvals that we deem in our sole discretion necessary to complete this exchange offer. These conditions are for our sole benefit. We may assert any one of these conditions regardless of the circumstances giving rise to it and may also waive any one of them, in whole or in part, at any time and from time to time, if we determine in our reasonable discretion that it has not been satisfied, subject to applicable law. We will not be deemed to have waived our rights to assert or waive these conditions if we fail at any time to exercise any of them. Each of these rights will be deemed an ongoing right which we may assert at any time and from time to time. If we determine that we may terminate this exchange offer because any of these conditions is not satisfied, we may: (1) refuse to accept and return to their holders any initial notes that have been tendered; (2) extend the exchange offer and retain all notes tendered before the expiration date, subject to the rights of the holders of these notes to withdraw their tenders; or -58- (3) waive any condition that has not been satisfied and accept all properly tendered notes that have not been withdrawn or otherwise amend the terms of this exchange offer in any respect as provided under the section in this prospectus entitled "-- Expiration Date; Extensions; Amendments; Termination". ACCOUNTING TREATMENT We will record the exchange notes at the same carrying value as the initial notes as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. We will amortize the costs of the exchange offer and the unamortized expenses related to the issuance of the exchange notes over the term of the exchange notes. EXCHANGE AGENT We have appointed The Bank of Nova Scotia Trust Company of New York as exchange agent for this exchange offer. You should direct all questions and requests for assistance on the procedures for tendering and all requests for additional copies of this prospectus or the letter of transmittal to the exchange agent as follows: By mail: The Bank of Nova Scotia Trust Company of New York 1 Liberty Plaza 23rd Floor New York, NY 10006 Attention: Exchanges By hand/overnight delivery: Facsimile Transmission: (212) 225-5436 Confirm by Telephone: (212) 225-5427 Attention: Exchanges FEES AND EXPENSES We will bear the expenses of soliciting tenders in this exchange offer, including fees and expenses of the exchange agent and trustee and accounting, legal, printing and related fees and expenses. We will not make any payments to brokers, dealers or other persons soliciting acceptances of this exchange offer. However, we will pay the exchange agent reasonable and customary fees for its services and will reimburse the exchange agent for its reasonable out-of-pocket expenses in connection with this exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries their reasonable out-of-pocket expenses for forwarding copies of the prospectus, letters of transmittal and related documents to the beneficial owners of the initial notes and for handling or forwarding tenders for exchange to their customers. We will pay all transfer taxes, if any, applicable to the exchange of initial notes in accordance with this exchange offer. However, tendering holders will pay the amount of any transfer taxes, whether imposed on the registered holder or any other persons, if: (1) certificates representing exchange notes or initial notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be registered or issued in the name of, any person other than the registered holder of the notes tendered; (2) tendered initial notes are registered in the name of any person other than the person signing the letter of transmittal; or -59- (3) a transfer tax is payable for any reason other than the exchange of the initial notes in this exchange offer. If you do not submit satisfactory evidence of the payment of any of these taxes or of any exemption from this payment with the letter of transmittal, we will bill you directly the amount of these transfer taxes. YOUR FAILURE TO PARTICIPATE IN THE EXCHANGE OFFER WILL HAVE ADVERSE CONSEQUENCES The initial notes were not registered under the Securities Act or under the securities laws of any state and you may not resell them, offer them for resale or otherwise transfer them unless they are subsequently registered or resold under an exemption from the registration requirements of the Securities Act and applicable state securities laws. If you do not exchange your initial notes for exchange notes in accordance with this exchange offer, or if you do not properly tender your initial notes in this exchange offer, you will not be able to resell, offer to resell or otherwise transfer the initial notes unless they are registered under the Securities Act or unless you resell them, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act. In addition, you will not necessarily be able to obligate us to register the initial notes under the Securities Act. DELIVERY OF PROSPECTUS Each broker-dealer that receives exchange notes for its own account in exchange for initial notes, where such initial notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. See "Plan of Distribution". DESCRIPTION OF THE EXCHANGE NOTES You can find the definitions of terms used in this description under the subheading "Definitions". In this description, the word "Compton" refers only to Compton Petroleum Corporation and not to any of its subsidiaries. Compton will issue the exchange notes under an indenture among itself, the Guarantors and The Bank of Nova Scotia Trust Company of New York, as trustee. See "Notice to Investors". The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the TRUST INDENTURE ACT OF 1939, as amended. The following description is a summary of the material provisions of the indenture. It does not restate the agreement in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the exchange notes. Copies of the indenture are available as set forth below under "-- Additional Information". Capitalized terms used in this description but not defined below under "-- Definitions" have the meanings assigned to them in the indenture. References to "US$" are to United States dollars and to "Cdn$" are to Canadian dollars. The registered Holder of a note will be treated as the owner of it for all purposes. Only registered Holders will have rights under the indenture. BRIEF DESCRIPTION OF THE EXCHANGE NOTES AND THE GUARANTEES THE NOTES The notes: o are general unsecured obligations of Compton; o are equal in right of payment to all existing and future unsecured senior Indebtedness of Compton; o are senior in right of payment with any permitted future subordinated Indebtedness of Compton; -60- o are unconditionally guaranteed by the Guarantors; and o are effectively subordinated to all secured Indebtedness of Compton and the Guarantors, including the Credit Facilities which are secured by substantially all of the assets of Compton and the Guarantors. THE GUARANTEES The notes are fully and unconditionally guaranteed on an unsecured senior basis by all of Compton's Subsidiaries and will be guaranteed by all of Compton's future Restricted Subsidiaries. Should a future Restricted Subsidiary of ours guarantee the notes, this guarantee will constitute a new issuance of securities under the Securities Act, and will require us to register such issuance under the Securities Act or effect such issuance under an exemption from registration. Each guarantee of the notes: o is a general senior unsecured obligation of the Guarantor; o is equal in right of payment to all existing and future unsecured senior Indebtedness of that Guarantor; and o is senior in right of payment with any permitted future senior subordinated Indebtedness of that Guarantor. As of the date of the indenture, all of our subsidiaries will be "Restricted Subsidiaries". However, under the circumstances described below under the subheading "-- Certain Covenants -- Designation of Restricted and Unrestricted Subsidiaries", we will be permitted to designate certain of our subsidiaries as "Unrestricted Subsidiaries". Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. Our Unrestricted Subsidiaries will not guarantee the notes. PRINCIPAL, MATURITY AND INTEREST Compton may issue an unlimited principal amount of notes under the indenture and up to US$165 million will be issued in the exchange notes. Compton may issue additional notes from time to time after this exchange offer. Any offering of additional notes is subject to the covenant described below under the caption "-- Certain Covenants --Incurrence of Indebtedness and Issuance of Preferred Stock". The initial notes, the exchange notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. Compton will issue notes in denominations of US$1,000 and integral multiples of US$1,000. The notes will mature on May 15, 2009. Interest on the notes will accrue at the rate of 9.90% per annum and will be payable semi-annually in arrears on May 15 and November 15, commencing on November 15, 2002. Compton will make each interest payment to the Holders of record on the immediately preceding May 1 and November 1. Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. METHODS OF RECEIVING PAYMENTS ON THE NOTES If a Holder has given wire transfer instructions to Compton in writing, Compton will pay all principal, interest and premium and Additional Interest, if any, on that Holder's notes in accordance with those instructions. All other payments on notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless Compton elects to make interest payments by check mailed to the Holders at their address set forth in the register of Holders. PAYING AGENT AND REGISTRAR FOR THE NOTES The trustee will initially act as paying agent and registrar. Compton may change the paying agent or registrar without prior notice to the Holders of the notes, and Compton or any of its Subsidiaries may act as paying agent or registrar. -61- TRANSFER AND EXCHANGE A Holder may transfer or exchange notes in accordance with the indenture. The registrar and the trustee may require a Holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. Compton is not required to transfer or exchange any note selected for redemption. Also, Compton is not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed. SUBSIDIARY GUARANTEES The notes will be guaranteed by each of Compton's current and future Restricted Subsidiaries. Should a future Restricted Subsidiary of ours guarantee the notes, this guarantee will constitute a new issuance of securities under the Securities Act, and will require us to register such issuance under the Securities Act or effect such issuance under an exemption from registration. The Subsidiary Guarantees will be joint and several unsecured obligations of the Guarantors. The obligations of each Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance under applicable law. See "Risk Factors -- Federal and State statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from guarantors". A Guarantor may not sell or otherwise dispose of all or substantially all of its assets to, or consolidate, amalgamate or merge with or into (whether or not such Guarantor is the surviving Person), another Person, other than Compton or another Guarantor, unless: (1) immediately after giving effect to that transaction, no Default or Event of Default exists; and (2) either: (a) the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger assumes all the obligations of that Guarantor under the indenture, its Subsidiary Guarantee and the registration rights agreement pursuant to a supplemental indenture reasonably satisfactory to the trustee; or (b) the Net Proceeds of such sale or other disposition are applied in accordance with the applicable provisions of the indenture. The Subsidiary Guarantee of a Guarantor will be released: (1) in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of Compton, if the sale or other disposition complies with the "Asset Sale" provisions of the indenture; or (2) in connection with any sale of all of the Capital Stock of a Guarantor to a Person that is not (either before or after giving effect to such transaction) a Subsidiary of Compton, if the sale complies with the "Asset Sale" provisions of the indenture; or (3) if Compton designates any Restricted Subsidiary that is a Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture. See "--Repurchase at the Option of Holders-- Asset Sales". OPTIONAL REDEMPTION At any time prior to May 15, 2005, Compton may on any one or more occasions redeem up to 35% of the aggregate principal amount of notes issued under the indenture at a redemption price of 109.90% of the principal amount, plus accrued -62- and unpaid interest and Additional Interest, if any, to the redemption date, with the net cash proceeds of one or more Equity Offerings; PROVIDED that: (1) at least 65% of the aggregate principal amount of notes issued under the indenture remains outstanding immediately after the occurrence of such redemption (excluding notes held by Compton and its Subsidiaries); and (2) the redemption occurs within 60 days of the date of the closing of such Equity Offering. If Compton becomes obligated to pay any Additional Amounts as a result of a change in the laws or regulations of Canada or any Canadian taxing authority, or a change in any official position regarding the application or interpretation thereof, which is publicly announced or becomes effective on or after the date of the indenture, Compton may, at its option, redeem the notes, in whole but not in part, upon not less than 30 nor more than 60 days' notice, at a redemption price equal to 100% of the principal amount thereof, plus accrued and unpaid interest and Additional Interest, if any, to the redemption date. Except pursuant to the preceding paragraphs, the notes will not be redeemable at Compton's option prior to May 15, 2006. After May 15, 2006, Compton may redeem all or a part of the notes upon not less than 30 nor more than 60 days' notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest and Additional Interest, if any, on the notes redeemed, to the applicable redemption date, if redeemed during the twelve-month period beginning on May 15 of the years indicated below: YEAR PERCENTAGE ---------------------------- ---------------- 2006.................... 104.950% 2007.................... 102.475% 2008 and thereafter..... 100.000% MANDATORY REDEMPTION Compton is not required to make mandatory redemption payments with respect to the notes. REPURCHASE AT THE OPTION OF HOLDERS CHANGE OF CONTROL If Compton does not make a Change of Control Offer in accordance with the terms of the indenture, each Holder of notes will have the right to require Compton to repurchase all or any part (equal to US$1,000 or an integral multiple of US$1,000) of that Holder's notes pursuant to a Change of Control Offer on the terms set forth in the indenture. In the Change of Control Offer, Compton will offer a Change of Control Payment in cash equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest and Additional Interest, if any, on the notes repurchased, to the date of purchase. Within 30 days following any Change of Control, Compton will mail a notice to each Holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase notes on the Change of Control Payment Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed, pursuant to the procedures required by the indenture and described in such notice. Compton will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, Compton will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such conflict. Compton's ability to make a Change of Control Offer is currently restricted by the terms of the Credit Agreement. On the Change of Control Payment Date, Compton or its designated agent will, to the extent lawful: -63- (1) accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer; (2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and (3) deliver or cause to be delivered to the trustee the notes accepted together with an officers' certificate stating the aggregate principal amount of notes or portions of notes being purchased by Compton. The paying agent will promptly mail to each Holder of notes properly tendered the Change of Control Payment for such notes, and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each Holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; PROVIDED that each new note will be in a principal amount of US$1,000 or an integral multiple of US$1,000. Compton will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date. The provisions described above that require Compton to make a Change of Control Offer following a Change of Control will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the Holders of the notes to require that Compton repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction. Compton will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by Compton and purchases all notes properly tendered and not withdrawn under the Change of Control Offer. The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of "all or substantially all" of the properties or assets of Compton and its Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all", there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of notes to require Compton to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of Compton and its Restricted Subsidiaries taken as a whole to another Person or group may be uncertain. ASSET SALES Compton will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless: (1) Compton (or the Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the fair market value of the assets or Equity Interests issued or sold or otherwise disposed of; (2) the fair market value is set forth in an officers' certificate delivered to the trustee; and (3) at least 75% of the consideration received in the Asset Sale by Compton or such Restricted Subsidiary is in the form of cash or Permitted Assets. For purposes of this provision, each of the following will be deemed to be cash: (a) any liabilities, as shown on Compton's or such Restricted Subsidiary's most recent balance sheet, of Compton or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any Subsidiary Guarantee) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases Compton or such Restricted Subsidiary from further liability; and -64- (b) any securities, notes or other obligations received by Compton or any such Restricted Subsidiary from such transferee that are contemporaneously, subject to ordinary settlement periods, converted by Compton or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion. Within 365 days after the receipt of any Net Proceeds from an Asset Sale, Compton or the applicable Restricted Subsidiary may apply those Net Proceeds: (1) to repay or prepay Indebtedness and other Obligations that is not subordinated to the Notes; (2) to acquire all or substantially all of the assets of, or a majority of the Voting Stock of, another Oil and Gas Business; (3) to make a capital expenditure; or (4) to acquire other long-term assets that are used or useful in the Oil and Gas Business. Pending the final application of any Net Proceeds, Compton may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. Any Net Proceeds from Asset Sales that are not applied or invested as provided in the preceding paragraph will constitute "Excess Proceeds". When the aggregate amount of Excess Proceeds exceeds US$10.0 million, Compton will make an Asset Sale Offer to all Holders of notes and all holders of other Indebtedness that is PARI PASSU (i.e., that ranks equally and ratably) with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets to purchase the maximum principal amount of notes and such other PARI PASSU Indebtedness that may be purchased out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of principal amount plus accrued and unpaid interest and Additional Interest, if any, to the date of purchase, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, Compton may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and other PARI PASSU Indebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other PARI PASSU Indebtedness to be purchased on a pro rata basis. Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero. Compton's ability to make an Asset Sale Offer is currently restricted by the terms of the Credit Agreement. Compton will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the indenture, Compton will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such conflict. The agreements governing Compton's other Indebtedness (including the Credit Agreement) contain prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale. In addition, the exercise by the Holders of notes of their right to require Compton to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchase on Compton. Finally, Compton's ability to pay cash to the Holders of notes upon a repurchase may be limited by Compton's then existing financial resources. SELECTION AND NOTICE If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption as follows: (1) if the notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the notes are listed; or -65- (2) if the notes are not listed on any national securities exchange, on a pro rata basis, by lot or by such method as the trustee deems fair and appropriate. No notes of US$1,000 or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional. If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the Holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption. COVENANTS Set forth below are covenants that are contained in the indenture. RESTRICTED PAYMENTS Compton will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly: (1) declare or pay any dividend or make any other payment or distribution on account of Compton's Equity Interests (including, without limitation, any payment on account of such Equity Interests in connection with any merger or consolidation involving Compton) or to the direct or indirect holders of Compton's Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of Compton); (2) purchase, retract, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving Compton), in whole or in part, any Equity Interests of Compton; (3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness that is subordinated to the notes or the Subsidiary Guarantees, except a payment of interest or principal at the Stated Maturity thereof; or (4) make any Restricted Investment; (all such payments and other actions set forth in these clauses (1) through (4) above being collectively referred to as "Restricted Payments"), unless, at the time of and after giving effect to such Restricted Payment: (1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment; and (2) Compton would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least US$1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption "-- Incurrence of Indebtedness and Issuance of Preferred Stock"; and (3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by Compton and its Restricted Subsidiaries after the date of the indenture (excluding Restricted Payments -66- permitted by clauses (2), (3) and (4) of the next succeeding paragraph), is less than the sum, without duplication, of: (a) 50% of the Consolidated Net Income of Compton for the period (taken as one accounting period) from the beginning of the first fiscal quarter during which the indenture is dated to the end of Compton's most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a loss, less 100% of such loss), PLUS (b) 100% of the aggregate net proceeds received by Compton (including the fair market value of any Oil and Gas Business acquired in a stock transaction) since the date of the indenture as a contribution to its common equity capital or from the issue or sale of Equity Interests of Compton (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of Compton that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or Disqualified Stock or debt securities) sold to a Subsidiary of Compton), PLUS (c) to the extent that any Restricted Investment that was made after the date of the indenture is sold for cash or otherwise liquidated or repaid for cash, the lesser of (i) the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any) and (ii) the initial amount of such Restricted Investment. So long as no Default has occurred and is continuing or would be caused thereby, the preceding provisions will not prohibit: (1) the payment of any dividend within 60 days after the date of declaration of the dividend, if at the date of declaration the dividend payment would have complied with the provisions of the indenture; (2) the redemption, repurchase, retirement, defeasance or other acquisition of any subordinated Indebtedness of Compton or any Guarantor or of any Equity Interests of Compton in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Restricted Subsidiary of Compton) of, Equity Interests of Compton (other than Disqualified Stock); PROVIDED that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition will be excluded from clause (3) (b) of the preceding paragraph; (3) the defeasance, redemption, repurchase or other acquisition of subordinated Indebtedness of Compton or any Guarantor with the net cash proceeds from an incurrence of Permitted Refinancing Indebtedness; (4) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of Compton or any Restricted Subsidiary of Compton held by any member of Compton's (or any of its Restricted Subsidiaries') management, directors or employees pursuant to any management equity subscription agreement, stock option agreement or similar agreement or upon the death, disability or termination of employment of such directors, officers or employees; PROVIDED that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed US$1.0 million in any calendar year or US$5.0 million in the aggregate since the date of the indenture; (5) payment of ordinary dividends on Disqualified Stock issued after the date of the indenture pursuant to the terms thereof as in effect on the date of issuance; PROVIDED, that such Disqualified Stock was issued in accordance with the covenant described below under the caption "-- Incurrence of Indebtedness and Issuance of Preferred Stock"; and (6) the making of other Restricted Payments in an aggregate amount not to exceed US$15.0 million since the date of the indenture. The amount of all Restricted Payments (other than cash) will be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by Compton or such Restricted Subsidiary, as the -67- case may be, pursuant to the Restricted Payment. The fair market value of any assets or securities that are required to be valued by this covenant will be determined by the Board of Directors whose resolution with respect thereto will be delivered to the trustee. INCURRENCE OF INDEBTEDNESS AND ISSUANCE OF PREFERRED STOCK Compton will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (in any such case, "incur") any Indebtedness (including Acquired Debt), and Compton will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock; PROVIDED, HOWEVER, that Compton may incur Indebtedness (including Acquired Debt) or issue Disqualified Stock, and the Guarantors may incur Indebtedness or issue preferred stock, if the Fixed Charge Coverage Ratio for Compton's most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued would have been at least 2.5 to 1, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the preferred stock or Disqualified Stock had been issued, as the case may be, at the beginning of such four-quarter period. The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, "Permitted Debt"): (1) the incurrence by Compton and its Restricted Subsidiaries of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit being deemed to have a principal amount equal to the maximum potential liability of Compton and its Restricted Subsidiaries thereunder) not to exceed the greater of: (a) Cdn$175.0 million, LESS the aggregate amount of all Net Proceeds of Asset Sales that have been applied by Compton or any of its Restricted Subsidiaries since the date of the indenture to permanently repay any term Indebtedness under a Credit Facility pursuant to the covenant described above under the caption "-- Repurchase at the Option of Holders-- Asset Sales" and LESS the aggregate amount of all commitment reductions with respect to any revolving credit borrowings under a Credit Facility that have been made by Compton or any of its Restricted Subsidiaries since the date of the indenture as a result of the application of Net Proceeds of Asset Sales pursuant to the covenant described above under the caption "--Repurchase at Option of Holders-- Asset Sales"; and (b) Cdn$95.0 million plus 15% of Adjusted Consolidated Net Tangible Assets as of the last day of the fiscal quarter for which internal financial statements are available and immediately preceding the date on which such additional Indebtedness is incurred; (2) Existing Indebtedness; (3) the incurrence by Compton and the Guarantors of Indebtedness represented by the notes and the related Subsidiary Guarantees to be issued on the date of the indenture and the Exchange Notes and the related Subsidiary Guarantees to be issued pursuant to the registration rights agreement; (4) the incurrence by Compton or any of the Guarantors of Indebtedness and Obligations represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of Compton or such Guarantor, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (4), not to exceed US$10.0 million at any time outstanding; (5) the incurrence by Compton or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to refund, refinance or replace Indebtedness (other than -68- intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph of this covenant or clauses (2), (3), (4), (5) or (13) of this paragraph; (6) the incurrence by Compton or any of its Restricted Subsidiaries of intercompany Indebtedness between or among Compton and any of its Restricted Subsidiaries; PROVIDED, HOWEVER, that: (a) if Compton or any Guarantor is the obligor on such Indebtedness, such Indebtedness must be unsecured; and (b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than Compton or a Restricted Subsidiary of Compton and (ii) any sale or other transfer of any such Indebtedness to a Person that is not either Compton or a Restricted Subsidiary of Compton; will be deemed, in each case, to constitute an incurrence of such Indebtedness by Compton or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6); (7) the incurrence by Compton or any of the Guarantors of Hedging Obligations, PROVIDED that such Hedging Obligations were incurred in the ordinary course of business and not for speculative purposes; (8) the guarantee by Compton or any of the Guarantors of Indebtedness of Compton or a Restricted Subsidiary of Compton that was permitted to be incurred by another provision of this covenant; (9) the accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant; PROVIDED, in each such case, that the amount thereof is included in Fixed Charges of Compton as accrued; (10) the incurrence by Compton or any Guarantor of Indebtedness and Obligations under Oil and Gas Hedging Contracts, PROVIDED that such Contracts were entered into in the ordinary course of business and not for speculative purposes; (11) production imbalances arising in the ordinary course of business; (12) Indebtedness and Obligations in connection with one or more standby letters of credit, Guarantees, performance or surety bond or other reimbursement obligations, in each case, issued in the ordinary course of business and not in connection with the borrowing of money or the obtaining of an advance or credit (other than advances or credit for goods and services in the ordinary course of business and on terms and conditions that are customary in the Oil and Gas Business, and other than the extension of credit represented by such letter of credit, Guarantee or performance or surety bond itself); and (13) the incurrence by Compton or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (13), not to exceed US$25.0 million. For purposes of determining compliance with this "Incurrence of Indebtedness and Issuance of Preferred Stock" covenant, in the event that an item of proposed Indebtedness meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (13) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, Compton will be permitted to classify, or later reclassify, such item of Indebtedness in whole or in part in any manner that complies with this covenant, including by allocation to more than one other type of Indebtedness. Indebtedness under Credit Facilities outstanding on the date on which notes are first issued and authenticated under the indenture will be deemed to have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. -69- Compton will not incur any additional Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of Compton unless such additional Indebtedness is also contractually subordinated in right of payment to the notes on substantially identical terms; PROVIDED, HOWEVER, that no Indebtedness of Compton will be deemed to be contractually subordinated in right of payment to any other Indebtedness of Compton solely by virtue of being unsecured. LIENS Compton will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind securing Indebtedness or trade payables (other than Permitted Liens) upon or with respect to any of their property or assets, now owned or hereafter acquired, unless all payments due under the indenture and the notes are secured on an equal and ratable basis with the obligations so secured until such time as such obligations are no longer secured by a Lien. DIVIDEND AND OTHER PAYMENT RESTRICTIONS AFFECTING RESTRICTED SUBSIDIARIES Compton will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to: (1) pay dividends or make any other distributions on its Capital Stock to Compton or any of its Restricted Subsidiaries, or with respect to any other interest or participation in, or measured by, its profits, or pay any indebtedness owed to Compton or any of its Restricted Subsidiaries; (2) make loans or advances to Compton or any of its Restricted Subsidiaries; or (3) transfer any of its properties or assets to Compton or any of its Restricted Subsidiaries. However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of: (1) agreements governing Existing Indebtedness or Credit Facilities as in effect or which come into effect on the date of the indenture and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of those agreements, PROVIDED that the amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are not materially less favourable to holders of notes, as determined by Compton's Board of Directors in their reasonable and good faith judgment; (2) the indenture, the notes and the Subsidiary Guarantees; (3) applicable law; (4) any instrument governing Indebtedness or Capital Stock of a Person acquired by Compton or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired, PROVIDED that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred; (5) customary non-assignment provisions in contracts entered into in the ordinary course of business and consistent with past practice; (6) purchase money obligations for property acquired in the ordinary course of business that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph; (7) any agreement for the sale or other disposition of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending its sale or other disposition; -70- (8) Permitted Refinancing Indebtedness, PROVIDED that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially less favourable to holders of notes, as determined by Compton's Board of Directors in their reasonable and good faith judgment; (9) agreements existing on the date of the indenture; (10) Liens securing Indebtedness otherwise permitted to be incurred under the provisions of the covenant described above under the caption "-- Liens" that limit the right of the debtor to dispose of the assets subject to such Liens; (11) provisions with respect to the disposition or distribution of assets or property in joint venture agreements, assets sale agreements, stock sale agreements and other similar agreements entered into in the ordinary course of business; and (12) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business. MERGER, CONSOLIDATION OR SALE OF ASSETS Compton may not, directly or indirectly: (1) amalgamate, consolidate or merge with or into another Person (whether or not Compton is the surviving corporation); or (2) sell, assign, transfer, convey or otherwise dispose of all or substantially all of the properties or assets of Compton and its Restricted Subsidiaries taken as a whole, in one or more related transactions, to another Person; unless: (1) either: (a) Compton is the surviving corporation; or (b) the Person formed by or surviving any such consolidation or merger (if other than Compton) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a corporation organized or existing under the laws of Canada or any province thereof or the United States, any state of the United States or the District of Columbia; (2) the Person formed by or surviving any such consolidation or merger (if other than Compton) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of Compton under the notes, the indenture and the registration rights agreement pursuant to agreements reasonably satisfactory to the trustee; (3) immediately after such transaction no Default or Event of Default exists; and (4) Compton or the Person formed by or surviving any such consolidation or merger (if other than Compton), or to which such sale, assignment, transfer, conveyance or other disposition has been made: (a) will have Consolidated Net Worth immediately after the transaction equal to or greater than the Consolidated Net Worth of Compton immediately preceding the transaction; and (b) will, on the date of such transaction after giving pro forma effect thereto and any related financing transactions as if the same had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least US$1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption "-- Incurrence of Indebtedness and Issuance of Preferred Stock"; and (5) the transactions will not result in Compton or the surviving corporation being required to make any deduction or withholding on account of taxes as described below under the caption "-- Payment of Additional Amounts" that Compton would not have been required to make had such transactions or series of transactions not occurred. -71- In addition, Compton may not, directly or indirectly, lease all or substantially all of its properties or assets, in one or more related transactions, to any other Person. This "Merger, Consolidation or Sale of Assets" covenant will not apply to a sale, assignment, transfer, conveyance or other disposition of assets between or among Compton and any of the Guarantors. TRANSACTIONS WITH AFFILIATES Compton will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an "Affiliate Transaction"), unless: (1) the Affiliate Transaction is on terms that are no less favorable to Compton or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by Compton or such Restricted Subsidiary with an unrelated Person; and (2) Compton delivers to the trustee: (a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of US$2.5 million, a resolution of the Board of Directors set forth in an officers' certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors; and (b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of US$15.0 million, an opinion as to the fairness to Compton or the relevant Restricted Subsidiary of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing in Canada or the United States. The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph: (1) any employment agreement entered into by Compton or any of its Restricted Subsidiaries in the ordinary course of business and consistent with the past practice of Compton or such Restricted Subsidiary; (2) transactions between or among Compton and/or its Restricted Subsidiaries; (3) transactions with a Person that is an Affiliate of Compton solely because Compton owns an Equity Interest in, or controls, such Person; (4) payment of reasonable and customary compensation or fees to, or the execution of customary expense reimbursement, indemnification or similar arrangements with, Compton or any of its Restricted Subsidiaries or any of their respective directors and officers in the ordinary course of business; (5) sales of Equity Interests (other than Disqualified Stock) to Affiliates of Compton; and (6) Restricted Payments that are permitted by the provisions of the indenture described above under the caption "-- Restricted Payments". ADDITIONAL SUBSIDIARY GUARANTEES If Compton or any of its Subsidiaries acquires or creates another Restricted Subsidiary after the date of the indenture, then that newly acquired or created Restricted Subsidiary will become a Guarantor and execute a supplemental indenture providing for a Subsidiary Guarantee and deliver an opinion of counsel reasonably satisfactory to the trustee that -72- such supplemental indenture has been duly authorized, executed and delivered and constitutes a legal, valid, binding and enforceable obligation, all within ten Business Days of the date on which it was acquired or created. DESIGNATION OF RESTRICTED AND UNRESTRICTED SUBSIDIARIES The Board of Directors of Compton may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate fair market value of all outstanding Investments owned by Compton and its Restricted Subsidiaries in the Subsidiary so designated will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the first paragraph of the covenant described above under the caption "-- Restricted Payments" or Permitted Investments, as determined by Compton. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. The Board of Directors of Compton may redesignate any Unrestricted Subsidiary to be a Restricted Subsidiary if the redesignation would not cause a Default. BUSINESS ACTIVITIES Compton will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material to Compton and its Restricted Subsidiaries taken as a whole. PAYMENTS FOR CONSENT Compton will not, and will not permit any of its Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration to or for the benefit of any Holder of notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid and is paid to all Holders of the notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement. PAYMENT OF ADDITIONAL AMOUNTS All payments made by Compton or on behalf of Compton with respect to the notes will be made without withholding or deduction for any taxes imposed by any Canadian taxing authority, unless required by law or the interpretation or administration thereof by the relevant taxing authority. If Compton is obligated to withhold or deduct any amount on account of taxes imposed by any Canadian taxing authority from any payment made with respect to the notes, Compton will: (1) make such withholding or deduction; (2) remit the full amount deducted or withheld to the relevant government authority in accordance with the applicable law; (3) pay such additional amounts ("Additional Amounts") as may be necessary so that the net amount received by each Holder (including Additional Amounts) after such withholding or deduction will not be less than the amount the Holder would have received if such taxes had not been withheld or deducted; (4) furnish to the trustee for the benefit of the Holders, within 30 days after the date of the payment of any taxes is due, an official receipt of the relevant government authorities for all amounts deducted or withheld, or if such receipts are not obtainable, other evidence of payment by Compton of those taxes; (5) indemnify and hold harmless each Holder, other than as described below, for the amount of: (a) any taxes (including interest and penalties) paid by such Holder as a result of payments made on or with respect thereto, and -73- (b) any taxes imposed with respect to any reimbursement under the preceding bullet or this bullet, but excluding any such taxes on such Holder's net income; and (6) at least 15 days prior to each date on which any Additional Amounts are payable, deliver to the trustee an officers' certificate setting forth the calculation of the Additional Amounts to be paid and such other information as the trustee may request to enable the trustee to pay such Additional Amounts to Holders on the payment date. Notwithstanding the foregoing, Compton will not pay Additional Amounts to a Holder in respect of a beneficial owner of a note: o with which Compton does not deal at arm's length (within the meaning of the Income Tax Act (Canada)) at the time of making such payment, or o which is subject to such taxes by reason of its being connected with Canada or any province or territory thereof otherwise than by the mere acquisition, holding or disposition of notes or the receipt of payments thereunder. Any reference in the indenture to the payment of principal, premium, if any, interest, Additional Interest, Change of Control or Asset Sale purchase price, redemption price or any other amount payable under or with respect to any note, will be deemed to include the payment of Additional Amounts to the extent that, in such context, Additional Amounts are, were or would be payable in respect thereof. Compton's obligation to make payments of Additional Amounts will survive any termination of the indenture or the defeasance of any rights thereunder. For a discussion of the exemption from Canadian withholding taxes applicable to payments under or with respect to the notes, see "-- Material Income Tax Considerations -- Canadian Federal Income Tax Considerations". REPORTS Whether or not required by the Commission, so long as any notes are outstanding, Compton will furnish to the Holders of notes, within the time periods specified in the Commission's rules and regulations or cause the trustee to furnish to the Holders: (1) (a) all annual financial information that would be required to be contained in a filing with the Commission on Forms 20-F or 40-F, as applicable (or any successor forms), containing the information required therein (or required in such successor form); and (b) for the first three quarters of each year, all quarterly financial information that would be required to be contained in a filing with the Commission on Form 6-K (or any successor form) containing in all material respects the financial information that would be required to be included in a filing on Form 10-Q (or any such successor form) that, regardless of applicable requirements shall, at a minimum, contain the information that would be required to be provided in quarterly reports under the laws of Canada or any province thereof to securityholders of a company with securities listed on the Toronto Stock Exchange, whether or not the Company has any of its securities so listed, in each case including a "Management's Discussion and Analysis of Financial Condition and Results of Operations" and, with respect to the annual information only, a report on the annual financial statements by Compton's certified independent accountants; and (2) all current reports that would otherwise be required to be filed with the Commission on Form 6-K if Compton were required to file such reports. If Compton has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management's Discussion and Analysis of Financial Condition -74- and Results of Operations, of the financial condition and results of operations of Compton and its Restricted Subsidiaries excluding the Unrestricted Subsidiaries. In addition, all such financial information and reports will contain all financial information required to be provided in quarterly reports under the laws of Canada or any province thereof to security holders of a company with securities listed on the Toronto Stock Exchange. In addition, following the consummation of the exchange offer, whether or not required by the Commission, Compton will file a copy of all of the information and reports referred to in clauses (1) and (2) above with the Commission for public availability within the time periods specified in the Commission's rules and regulations (unless the Commission will not accept such a filing). EVENTS OF DEFAULT AND REMEDIES Each of the following is an Event of Default: (1) default for 30 days in the payment when due of interest on, or Additional Interest with respect to the notes; (2) default in payment when due of the principal of, or premium, if any, on the notes; (3) failure by Compton or any of its Restricted Subsidiaries to comply with the provisions described under the captions "-- Repurchase at the Option of Holders -- Change of Control", "-- Repurchase at the Option of Holders -- Asset Sales", or "-- Certain Covenants -- Merger, Consolidation or Sale of Assets"; (4) failure by Compton or any of its Restricted Subsidiaries to comply with any of the other agreements in the indenture for 60 days after written notice has been given to Compton by the trustee or to Compton and the trustee by Holders of at least 25% of the outstanding principal amount of the notes; (5) default under any other mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by Compton or any of its Restricted Subsidiaries (or the payment of which is guaranteed by Compton or any of its Restricted Subsidiaries) whether such Indebtedness or guarantee now exists, or is created after the date of the indenture, if that default: (a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the applicable grace or cure period provided in such Indebtedness on the date of such default (a "Payment Default"); or (b) results in the acceleration of such Indebtedness prior to its express maturity, and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default which remains outstanding or the maturity of which has been so accelerated, aggregates US$10.0 million or more, PROVIDED that if any such default is cured or waived or any such acceleration rescinded, or such Indebtedness is repaid, within a period of 10 days from the continuation of such default beyond the applicable grace or cure period or the occurrence of such acceleration, as the case may be, such Event of Default under the indenture and any consequential acceleration of the notes shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree; (6) failure by Compton or any of its Restricted Subsidiaries to pay final judgments aggregating in excess of US$10.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; and (7) except as permitted by the indenture, any Subsidiary Guarantee shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Significant Subsidiary, or any Person acting on behalf of any Significant Subsidiary, shall deny or disaffirm its obligations under its Subsidiary Guarantee; and -75- (8) certain events of bankruptcy or insolvency described in the indenture with respect to Compton or any of its Significant Subsidiaries. In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to Compton, any Subsidiary that is a Significant Subsidiary or any group of Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the Holders of at least 25% in principal amount of the then outstanding notes may declare all the notes to be due and payable immediately. Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, Holders of a majority in principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from Holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal or interest or Additional Interest. The Holders of a majority in aggregate principal amount of the notes then outstanding by notice to the trustee may on behalf of the Holders of all of the notes waive any existing Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of interest or Additional Interest on, or the principal of, the notes. In the case of any Event of Default occurring by reason of any willful action or inaction taken or not taken by or on behalf of Compton with the intention of avoiding payment of the premium that Compton would have had to pay if Compton then had elected to redeem the notes pursuant to the optional redemption provisions of the indenture, an equivalent premium will also become and be immediately due and payable to the extent permitted by law upon the acceleration of the notes. If an Event of Default occurs prior to May 15, 2006, by reason of any willful action (or inaction) taken (or not taken) by or on behalf of Compton with the intention of avoiding the prohibition on redemption of the notes prior to May 15, 2006, then the premium specified in the indenture will also become immediately due and payable to the extent permitted by law upon the acceleration of the notes. Compton is required to deliver to the trustee annually a statement regarding compliance with the indenture. Upon becoming aware of any Default or Event of Default, Compton is required to deliver promptly to the trustee a statement specifying such Default or Event of Default. NO PERSONAL LIABILITY OF DIRECTORS, OFFICERS, EMPLOYEES AND STOCKHOLDERS No director, officer, employee, incorporator or stockholder of Compton or any Guarantor, as such, will have any liability for any obligations of Compton or the Guarantors under the notes, the indenture, the Subsidiary Guarantees, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws. LEGAL DEFEASANCE AND COVENANT DEFEASANCE Compton may, at its option and at any time, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Subsidiary Guarantees ("Legal Defeasance") except for: (1) the rights of Holders of outstanding notes to receive payments in respect of the principal of, or interest or premium and Additional Interest, if any, on such notes when such payments are due from the trust referred to below; (2) Compton's obligations with respect to the notes concerning issuing temporary notes, registration of notes, replacing mutilated, destroyed, lost or stolen notes, maintaining an office or agency for payment and segregating and holding money for security payments held in trust; -76- (3) the rights, powers, trusts, duties and immunities of the trustee, and Compton's and the Guarantor's obligations in connection therewith; and (4) the Legal Defeasance provisions of the indenture. In addition, Compton may, at its option and at any time, elect to have the obligations of Compton and the Guarantors released with respect to certain covenants that are described in the indenture ("Covenant Defeasance") and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, reorganization and insolvency events) described under "-- Events of Default and Remedies" will no longer constitute an Event of Default with respect to the notes. In order to exercise either Legal Defeasance or Covenant Defeasance: (1) Compton must irrevocably deposit with the trustee, in trust, for the benefit of the Holders of the notes, cash in U.S. dollars, Government Securities that may not be redeemed by the holder prior to their stated maturity or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants in Canada or the United States, to pay the principal of, or interest and premium and Additional Interest, if any, on the outstanding notes on the stated maturity or on the applicable redemption date, as the case may be, and Compton must specify whether the notes are being defeased to maturity or to a particular redemption date; (2) in the case of Legal Defeasance, Compton has delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that (a) Compton has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the date of the indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the Holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred; (3) in the case of Covenant Defeasance, Compton has delivered to the trustee (a) an opinion of counsel reasonably acceptable to the trustee confirming that the Holders of the outstanding notes will not recognize income, gain or loss for U.S. federal income tax purposes as a result of such Covenant Defeasance and will be subject to U.S. federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred and (b) an opinion of counsel qualified to practice in Canada or a ruling from Revenue Canada, Taxation to the effect that Holders of the outstanding notes who are not resident in Canada will not recognize income, gain or loss for Canadian federal, provincial or territorial income tax or other tax purposes as a result of such deposit and defeasance and will only be subject to Canadian federal, provincial income tax and other taxes on the same amounts, in the same manner and at the same times as would have been the case had such deposit and defeasance not occurred; (4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit); (5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under any material agreement or instrument (other than the indenture) to which Compton or any of its Restricted Subsidiaries is a party or by which Compton or any of its Restricted Subsidiaries is bound; (6) Compton must deliver to the trustee an officers' certificate stating that the deposit was not made by Compton with the intent of preferring the Holders of notes over the other creditors of Compton with the intent of defeating, hindering, delaying or defrauding creditors of Compton or others; and -77- (7) Compton must deliver to the trustee an officers' certificate and an opinion of counsel, each stating that all conditions precedent under the indenture relating to the Legal Defeasance or the Covenant Defeasance have been complied with. AMENDMENT, SUPPLEMENT AND WAIVER Except as provided in the next three succeeding paragraphs, the indenture or the notes may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes), and any existing Default or compliance with any provision of the indenture or the notes may be waived with the consent of the Holders of a majority in principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes). Without the consent of each Holder affected, an amendment or waiver may not (with respect to any notes held by a non-consenting Holder): (1) reduce the principal amount of notes whose Holders must consent to an amendment, supplement or waiver; (2) reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption of the notes (other than provisions relating to the covenants described above under the caption "-- Repurchase at the Option of Holders"); (3) reduce the rate of or change the time for payment of interest on any note; (4) waive a Default or Event of Default in the payment of principal of, or interest or premium, or Additional Interest, if any, on the notes (except a rescission of acceleration of the notes by the Holders of at least a majority in aggregate principal amount of the notes and a waiver of the payment default that resulted from such acceleration); (5) make any note payable in money other than that stated in the notes; (6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of Holders of notes to receive payments of principal of, or interest or premium or Additional Interest, if any, on the notes; (7) waive a redemption payment with respect to any note (other than a payment required by one of the covenants described above under the caption "--Repurchase at the Option of Holders"); (8) release any Guarantor from any of its obligations under its Subsidiary Guarantee or the indenture, except in accordance with the terms of the indenture; or (9) make any change in the preceding amendment and waiver provisions. Notwithstanding the preceding, without the consent of any Holder of notes, Compton, the Guarantors and the trustee may amend or supplement the indenture or the notes: (1) to cure any ambiguity, defect or inconsistency; (2) to provide for uncertificated notes in addition to or in place of certificated notes; (3) to provide for the assumption of Compton's and each Guarantor's obligations to Holders of notes in the case of a merger or consolidation or sale of all or substantially all of Compton's assets; (4) to make any change that would provide any additional rights or benefits to the Holders of notes or that does not adversely affect the legal rights under the indenture of any such Holder; or -78- (5) to comply with requirements of the Commission in order to effect or maintain the qualification of the indenture under the Trust Indenture Act. SATISFACTION AND DISCHARGE The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when: (1) either: (a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to Compton, have been delivered to the trustee for cancellation; or (b) all notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year and Compton or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the Holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient to pay and discharge the principal, premium and Additional Interest, if any, and accrued interest to the date of maturity or redemption; (2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which Compton or any Guarantor is a party or by which Compton or any Guarantor is bound; (3) Compton or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and (4) Compton has delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the notes at maturity or the redemption date, as the case may be. In addition, Compton must deliver an officers' certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied. CONCERNING THE TRUSTEE If the trustee becomes a creditor of Compton or any Guarantor, the indenture limits its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the Commission for permission to continue or resign. The Holders of a majority in principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any Holder of notes, unless such Holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense. -79- ADDITIONAL INFORMATION Anyone who receives this prospectus may obtain a copy of the indenture and registration rights agreement without charge by writing to Compton Petroleum Corporation, Suite 3300, 425 - 1st Street S.W., Calgary, Alberta, T2P 3L8, Attention: Corporate Secretary. DEFINITIONS Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided. "ACQUIRED DEBT" means, with respect to any specified Person: (1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Restricted Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person; and (2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person; provided that any Indebtedness of such Person that is redeemed, defeased, retired or otherwise repaid at the time of or immediately upon consummation of the transaction by which such other Person is merged with or into, or becomes a Restricted Subsidiary of, such specified Person, or such assets are acquired from such Person, will not be Acquired Debt. "ADDITIONAL AMOUNTS" has the meaning assigned to that term under the caption "-- Payments of Additional Amounts". "ADJUSTED CONSOLIDATED NET TANGIBLE ASSETS" means, without duplication, as of the date of determination; the sum of: (1) discounted future net revenues from proved oil and gas reserves of Compton and its Restricted Subsidiaries calculated in accordance with Commission guidelines (before any provincial, state or federal income taxes), as confirmed by a nationally recognized firm of independent petroleum engineers (which shall include Outtrim Szabo Associates Ltd.) in a reserve report prepared as of the end of Compton's most recently completed fiscal year, as INCREASED BY, as of the date of determination, the discounted future net revenues of (a) estimated proved oil and gas reserves acquired since the date of such year-end reserve report, and (b) estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves since the date of such year-end reserve report due to exploration, development or exploitation activities, in each case, calculated in accordance with Commission guidelines (utilizing the prices utilized in such year-end reserve report), AND DECREASED BY, as of the date of determination, the estimated discounted future net revenues of (c) estimated proved oil and gas reserves produced or disposed of since the date of such year-end reserve report and (d) reductions in estimated proved oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since the date of such year-end reserve report due to changes in geological conditions or other factors that would, in accordance with standard industry practice, cause such revisions, in each case calculated in accordance with Commission guidelines (utilizing the prices in such year-end reserve report), PROVIDED that, in the case of each of the determinations made pursuant to clauses (a) through (d), such increases and decreases shall be as estimated by Compton's petroleum engineers, unless there is a Material Change as a result of such acquisitions, dispositions or revisions, in which case the discounted future net revenues utilized for purposes of this clause (1) shall be confirmed in a written report of a nationally recognized firm of independent petroleum engineers (which shall include Outtrim Szabo Associates Ltd.) delivered to the trustee (which report shall be reasonably satisfactory in form and substance to the trustee), -80- (2) the capitalized costs that are attributable to oil and gas properties of Compton and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on Compton's books and records as of a date no earlier than the date of Compton's most recent available internal quarterly financial statements, (3) the Consolidated Net Working Capital of Compton on a date no earlier than the date of Compton's most recently available internal quarterly financial statements, and (4) the greater of (a) the net book value of other tangible assets of Compton on a date no earlier than the date of Compton's most recently available internal quarterly financial statements or (b) the appraised value, as estimated by independent appraisers, of other tangible assets of Compton and its Restricted Subsidiaries, in either case, as of the date of Compton's most recently available internal quarterly financial statements, MINUS the sum of: (1) minority interests, (2) any net gas balancing liabilities of Compton and its Restricted Subsidiaries reflected in Compton's most recently available internal quarterly financial statements, (3) to the extent included in the first clause (1) above, the discounted future net revenues, calculated in accordance with Commission guidelines utilizing the prices utilized in Compton's year-end reserve report, attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of Compton and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto, (4) the discounted future net revenues, calculated in accordance with Commission guidelines, attributable to reserves subject to Dollar-Denominated Production Payments that, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in the first clause (1) above, would be necessary to fully satisfy the payment obligations of Compton and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto, and (5) the discounted future net revenues, calculated in accordance with Commission guidelines utilizing the prices utilized in Compton's year-end reserve report, attributable to reserves that are subject to participation, partnership, vendor financing or other agreements then in effect, or that are otherwise required to be delivered to third parties but only to the extent that such third parties are then entitled to such reserves, or in the case of vendor financing or other encumbrances reduced only by the value of such encumbrances. If Compton changes its method of accounting from the full cost method to the successful efforts method or a similar method of accounting, "Adjusted Consolidated Net Tangible Assets" will continue to be calculated as if Compton were still using the full cost method of accounting. "AFFILIATE" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, "control", as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; PROVIDED that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control. For purposes of this definition, the terms "controlling", "controlled by" and "under common control with" have correlative meanings. "ASSET SALE" means: -81- (1) the sale, lease, conveyance or other disposition of any assets or rights, other than sales of inventory in the ordinary course of business consistent with past practices; PROVIDED that the sale, conveyance or other disposition of all or substantially all of the assets of Compton and its Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption "-- Repurchase at the Option of Holders-- Change of Control" and/or the provisions described above under the caption "--Certain Covenants-- Merger, Consolidation or Sale of Assets" and not by the provisions of the Asset Sale covenant; and (2) the issuance of Equity Interests in any of Compton's Restricted Subsidiaries or the sale of Equity Interests in any of its Subsidiaries. Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale: (1) any single transaction or series of related transactions that involves assets having a fair market value of less than US$1.0 million; (2) a transfer of assets between or among Compton and its Restricted Subsidiaries; (3) an issuance of Equity Interests by a Subsidiary to Compton or to another Subsidiary; (4) consisting of worn-out, obsolete or retired equipment or facilities in the ordinary course of business; (5) the sale or lease of equipment, inventory, including current production, accounts receivable or other assets in the ordinary course of business; (6) the sale or other disposition of cash or Cash Equivalents; (7) any transfer of properties or assets (including Capital Stock) that is governed by the provisions of the indenture described under "-- Certain Covenants -- Consolidation, Merger and Sale of Assets"; or that is a Restricted Payment or Permitted Investment that is permitted by the covenant described above under the caption "-- Certain Covenants -- Restricted Payments"; (8) the sale or transfer (whether or not in the ordinary course of business) of oil and gas properties or direct or indirect interests in real property, provided that at the time of such sale or transfer such properties do not have associated with them any proved reserves; (9) the abandonment, farm-out, lease or sublease of developed or undeveloped oil and gas properties in the ordinary course of business or resulting from any pooling, unit or farm-out agreement entered into in the ordinary course of business; (10) the trade or exchange by the Company or any Subsidiary of the Company of any oil and gas property owned or held by the Company or such Subsidiary for any oil and gas property owned or held by another Person; (11) the sale or transfer of hydrocarbons or other mineral products in the ordinary course of business; and (12) a Permitted Investment. "BENEFICIAL OWNER" has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular "person" (as that term is used in Section 13(d)(3) of the Exchange Act), such "person" will be deemed to have beneficial ownership of all securities that such "person" has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms "Beneficially Owns" and "Beneficially Owned" have a corresponding meaning. -82- "BOARD OF DIRECTORS" means: (1) with respect to a corporation, the board of directors of the corporation; (2) with respect to a partnership, the Board of Directors of the corporation which is the general partner of the partnership; and (3) with respect to any other Person, the board or committee of such Person serving a similar function. "CAPITAL LEASE OBLIGATION" means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be classified and accounted for as a capitalized lease obligation on a balance sheet in accordance with GAAP. "CAPITAL STOCK" means: (1) in the case of a corporation, corporate stock of any class; (2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock; (3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and (4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person. "CASH EQUIVALENTS" means: (1) United States or Canadian dollars; (2) securities issued by or directly and fully guaranteed or insured by the federal governments of Canada or the United States of America or any agency or instrumentality thereof (PROVIDED that the full faith and credit of the federal governments of Canada or the United States is pledged in support of those securities) having maturities of not more than 270 days from the date of acquisition; (3) certificates of deposit and eurodollar time deposits with maturities of 270 days or less from the date of acquisition, bankers' acceptances with maturities not exceeding 270 days and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any United States commercial bank or any Canadian chartered bank having capital and surplus in excess of US$500.0 million and a Thomson Bank Watch Rating of "B" or better; (4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above; (5) commercial paper rated at least P-1 by Moody's Investors Service, Inc. or A-1 by Standard & Poor's Rating Services or at least R-1 by Dominion Bond Rating Service and in each case maturing within 270 days after the date of acquisition; and (6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition. "CHANGE OF CONTROL" means the occurrence of any of the following events: -83- (1) the direct or indirect sale, transfer, conveyance or other disposition (other than by way of merger, amalgamation or consolidation), in one or a series of related transactions, of all or substantially all of the properties or assets of Compton and its Restricted Subsidiaries, taken as a whole, to any "person" (as that term is used in Section 13(d)(3) of the Exchange Act); (2) the adoption or approval by the Board of Directors of Compton or its stockholders of a plan relating to the liquidation or dissolution of Compton; (3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any "person" (as defined above) becomes the Beneficial Owner, directly or indirectly, of more than 50% the Voting Stock of Compton, measured by voting power rather than number of shares; or (4) the first day on which a majority of the members of the Board of Directors of Compton are not Continuing Directors. "CONSOLIDATED CASH FLOW" means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period PLUS: (1) an amount equal to any extraordinary loss, plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such losses were deducted in computing such Consolidated Net Income; PLUS (2) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income; PLUS (3) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized (including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers' acceptance financings, and net of the effect of all payments made or received pursuant to Hedging Obligations), to the extent that any such expense was deducted in computing such Consolidated Net Income; PLUS (4) depreciation, depletion, amortization (including amortization of goodwill and other intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period) and other non-cash expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization and other non-cash expenses were deducted in computing such Consolidated Net Income; MINUS (5) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business; and MINUS (6) to the extent included in determining Consolidated Net Income, the sum of: (a) the amount of deferred revenues that are amortized during such period and that are attributable to reserves that are subject to Volumetric Production Payments; and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, in each case, on a consolidated basis and determined in accordance with GAAP. -84- "CONSOLIDATED NET INCOME" means, with respect to any specified Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; PROVIDED that: (1) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person; (2) the Net Income of any Restricted Subsidiary will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders; (3) the Net Income (but not loss) of any Person acquired in a pooling of interests transaction for any period prior to the date of such acquisition will be excluded; (4) the cumulative effect of a change in accounting principles will be excluded; (5) any non-cash charges related to a ceiling test write-down under GAAP will be excluded; and (6) to the extent not otherwise included, any gain on the disposition of a Restricted Investment will be included. "CONSOLIDATED NET WORKING CAPITAL" of any Person as of any date of determination means the difference (shown on the balance sheet of such Person and its Restricted Subsidiaries determined on a consolidated basis in accordance with GAAP as of the end of the most recent fiscal quarter of such Person for which internal financial statements are available) between (i) all current assets of such Person and its Restricted Subsidiaries and (ii) all current liabilities of such Person and its Restricted Subsidiaries except the current portion of long-term Indebtedness. "CONSOLIDATED NET WORTH" means, with respect to any specified Person as of any date, the sum of: (1) the consolidated equity of the common stockholders of such Person and its consolidated Subsidiaries as of such date; plus (2) the respective amounts reported on such Person's balance sheet as of such date with respect to any series of preferred stock (other than Disqualified Stock) that by its terms is not entitled to the payment of dividends unless such dividends may be declared and paid only out of net earnings in respect of the year of such declaration and payment, but only to the extent of any cash received by such Person upon issuance of such preferred stock. "CONTINUING DIRECTORS" means, as of any date of determination, any member of the Board of Directors of Compton who: (1) was a member of such Board of Directors on the date of the indenture; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election. "CREDIT AGREEMENT" means that certain Amended and Restated Credit Agreement dated as of the date of the Indenture, among Compton, as borrower, certain Canadian chartered banks, as lenders, Bank of Montreal, as lead arranger and administrative agent, The Bank of Nova Scotia, as syndication agent, and The Toronto-Dominion Bank, as documentation agent, including any related notes, debentures, pledges, guarantees, security documents, instruments and agreements executed from time to time in connection therewith, and in each case as amended, modified, restated, renewed, replaced or refinanced from time to time, including any agreement extending the -85- maturity of, refinancing, replacing or otherwise restructuring or adding Subsidiaries as additional borrowers or guarantors thereunder, and all or any portion of the Indebtedness and other Obligations under such agreement or agreements or any successor or replacement agreement or any agreements, and whether by the same or any other agent, lender or group of lenders. For greater certainty, it is acknowledged that Interest Rate Agreements, Currency Agreements and Oil and Gas Hedging Contracts entered into with a person that at that time is a lender (or an affiliate thereof) under the Credit Agreement are separate from, are not included within and do not form part of any above inclusions of the Credit Agreement. "CREDIT FACILITIES" means one or more credit or debt facilities (including, without limitation, under the Credit Agreement) or commercial paper facilities, in each case with banks or other institutional lenders providing for , among other things, revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time. "CURRENCY AGREEMENT" means any financial arrangement entered into between a Person (or its Restricted Subsidiaries) and a counterparty on a case by case basis in connection with a foreign exchange futures contract, currency swap agreement, currency option or currency exchange or other similar currency related transactions, the purpose of which is to mitigate or eliminate its exposure to fluctuations in exchange rates and currency values. "DEFAULT" means the occurrence of any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default under the indenture. "DISQUALIFIED STOCK" means, with respect to any Person, any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, prior to the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require Compton to repurchase such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that Compton may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption "-- Certain Covenants -- Restricted Payments". "DOLLAR-DENOMINATED PRODUCTION PAYMENTS" means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith. "EQUITY INTERESTS" means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock). "EQUITY OFFERINGS" means any public or private sale of equity securities of Compton (other than Disqualified Stock) generating gross proceeds to Compton of at least US$10.0 million. "EXISTING INDEBTEDNESS" means all Indebtedness of Compton and its Subsidiaries (other than Indebtedness under the Credit Agreement) in existence on the date of the indenture. "FAIR MARKET VALUE" means, with respect to any asset, property or service, the price that could be negotiated in an arm's length free market transaction, for cash, between a willing seller and a willing buyer, neither of whom is under pressure or compulsion to complete the transaction. Unless otherwise specified in the indenture, in the case of a transaction with respect to Compton or any of its Restricted Subsidiaries exceeding US$10.0 million, fair market value will be determined by the Board of Directors of Compton acting in good faith and will be evidenced by a resolution delivered to the trustee. "FIXED CHARGES" means, with respect to any specified Person for any period, the sum, without duplication, of: -86- (1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued, including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers' acceptance financings, and net of the effect of all payments made or received pursuant to Interest Rate Agreements; PLUS (2) the consolidated interest of such Person and its Restricted Subsidiaries that was capitalized during such period; PLUS (3) any interest expense on Indebtedness of another Person that is Guaranteed by such Person (other than such Person or its Restricted Subsidiaries) or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such Guarantee or Lien is called upon; PLUS (4) the product of (a) all dividends, whether paid or accrued and whether or not in cash, on any series of Disqualified Stock of such Person or any of its Restricted Subsidiaries, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, provincial, state and local statutory tax rate of such Person or any of its Restricted Subsidiaries, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP. "FIXED CHARGE COVERAGE RATIO" means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person and its Restricted Subsidiaries for such period to the Fixed Charges of such Person and its Restricted Subsidiaries for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, Guarantees, repays, repurchases or redeems any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the "Calculation Date"), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom as if the same had occurred at the beginning of the applicable four-quarter reference period. In addition, for purposes of calculating the Fixed Charge Coverage Ratio: (1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related financing transactions, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date will be given pro forma effect as if they had occurred on the first day of the four-quarter reference period and Consolidated Cash Flow for such reference period will be calculated on a pro forma basis in accordance with Regulation S-X under the Securities Act, but without giving effect to clause (3) of the proviso set forth in the definition of Consolidated Net Income; (2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded; and (3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date. "GAAP" means generally accepted accounting principles, consistently applied, which are in effect in Canada from time to time. -87- "GUARANTEE" means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. "GUARANTORS" means each of: (1) Compton's existing Subsidiaries; and (2) any other Subsidiary that executes a Subsidiary Guarantee in accordance with the provisions of the indenture; and their respective successors and assigns. "HEDGING OBLIGATIONS" means, with respect to any specified Person, the outstanding amount of all obligations of such Person and its Restricted Subsidiaries under all Currency Agreements and all Interest Rate Agreements, together with all interest, fees and other amounts payable thereon or in connection therewith. "INDEBTEDNESS" means, with respect to any specified Person at any date, any indebtedness of such Person, whether or not contingent: (1) in respect of borrowed money; (2) evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof); (3) in respect of banker's acceptances; (4) representing Capital Lease Obligations; (5) representing the balance deferred and unpaid of the purchase price of any property, except any such balance that constitutes an accrued expense or trade payable; (6) representing any Hedging Obligations; (7) in respect of Production Payments; (8) in respect of Oil and Gas Hedging Contracts; or (9) all conditional sale obligations and all obligations under title retention agreements, but excluding a title retention agreement to the extent it constitutes an operating lease under Canadian law, if and to the extent any of the preceding items (other than letters of credit, Hedging Obligations and Oil and Gas Hedging Contracts) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term "Indebtedness" includes all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) and, to the extent not otherwise included, the Guarantee by the specified Person of any indebtedness of any other Person. The amount of any Indebtedness outstanding as of any date will be: (1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount; and (2) the principal amount of the Indebtedness, together with any interest on the Indebtedness that is more than 30 days past due, in the case of any other Indebtedness. -88- "INTEREST RATE AGREEMENT" means any financial arrangement entered into between a Person (or its Restricted Subsidiaries) and a counterparty on a case by case basis in connection with interest rate swap transactions, interest rate options, cap transactions, floor transactions, collar transactions and other similar interest rate protection related transactions, the purpose of which is to mitigate or eliminate its exposure to fluctuations in interest rates. "INVESTMENTS" means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. "Investments" shall exclude extensions of trade credit in the ordinary course of business for terms not greater than 90 days. If Compton or any Subsidiary of Compton sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary of Compton such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of Compton, Compton will be deemed to have made an Investment on the date of any such sale or disposition equal to the fair market value of Compton's Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption "-- Certain Covenants -- Restricted Payments". The acquisition by Compton or any Subsidiary of Compton of a Person that holds an Investment in a third Person will be deemed to be an Investment by Compton or such Subsidiary in such third Person in an amount equal to the fair market value of the Investment held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption "-- Certain Covenants -- Restricted Payments". "LIEN" means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, charge, security interest or encumbrance upon or with respect to any property of any kind, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, but excluding a title retention agreement to the extent it constitutes an operating lease under Canadian law, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction. "MATERIAL CHANGE" means an increase or decrease (excluding changes that result solely from changes in prices) of more than 30% during a fiscal quarter in the estimated discounted future net cash flows from proved oil and gas reserves of Compton and its Restricted Subsidiaries, calculated in accordance with the first clause (1) of the definition of Adjusted Consolidated Net Tangible Assets; provided, however, that the following will be excluded from the calculation of Material Change: (1) the estimated future net cash flows from: (2) any acquisitions during the quarter of oil and gas reserves that have been audited by a nationally recognized firm of independent petroleum engineers (which shall include Outtrim Szabo Associates Ltd.), and (3) any disposition of properties held at the beginning of such quarter that have been disposed of as provided in the covenant described under the caption "-- Asset Sales". "NET INCOME" means, with respect to any specified Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however: (1) any gain (but not loss), together with any related provision for taxes on such gain (but not loss), realized in connection with: (a) any Asset Sale; or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries; and (2) Zany extraordinary gain (but not loss), together with any related provision for taxes on such extraordinary gain (but not loss). -89- "NET PROCEEDS" means the aggregate cash proceeds received by Compton or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees, and sales commissions, and any relocation expenses incurred as a result of the Asset Sale, taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements, and amounts required to be applied to the repayment of Indebtedness, other than Indebtedness under a Credit Facility secured by a Lien on the asset or assets that were the subject of such Asset Sale and any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP. "NON-RECOURSE DEBT" means Indebtedness: (1) as to which neither Compton nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable as a guarantor or otherwise, or (c) constitutes the lender; (2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any other Indebtedness of Compton or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of the Indebtedness to be accelerated or payable prior to its stated maturity; and (3) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of Compton or any of its Restricted Subsidiaries subject to customary exceptions for environmental, title, fraud and similar matters. "OBLIGATIONS" means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness. "OIL AND GAS BUSINESS" means: (1) the acquisition, exploration, development, operation and disposition of interests in oil, gas and other hydrocarbon properties, (2) the gathering, marketing, treating, processing, storage, selling and transporting of any production from such interests or properties, (3) the exploration for or development, production, treatment, processing, storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith, (4) evaluating, participating in or pursuing any other activity or opportunity that is primarily related to clauses (1) through (3) above, and (5) any activity that is ancillary to or necessary or appropriate for the activities described in clauses (1) through (4) of this definition, provided that, in respect of Compton, the determination of what reasonably constitutes a permissible Oil and Gas Business pursuant to clauses (1) to (5) above shall be made in good faith by the Board of Directors of Compton. "OIL AND GAS HEDGING CONTRACTS" means any transaction, arrangement or agreement entered into between a Person (or any of its Restricted Subsidiaries) and a counterparty on a case by case basis, including any futures contract, a commodity option, a swap, a forward sale or otherwise, the purpose of which is to mitigate, manage or eliminate its exposure to fluctuations in commodity prices, including contracts settled by physical delivery of the commodity not settled within 60 days of the date of any such contract; provided that Production Payments will not be treated as Oil and Gas Hedging Contracts for the purposes of the indenture. -90- "OIL AND GAS INVESTMENTS" means any Investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing or transporting oil and gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including, without limitation: (1) ownership interests in oil and gas properties, processing facilities or gathering systems or ancillary real property interests and (2) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements with third parties. "PERMITTED ASSETS" means any and all long-term assets that are used or useful in an Oil and Gas Business. "PERMITTED INVESTMENTS" means, without duplication: (1) any Investment in Compton or in a Restricted Subsidiary of Compton; (2) any Investment in Cash Equivalents; (3) any Investment by Compton or any Restricted Subsidiary of Compton in a Person, if as a result of such Investment: (a) such Person becomes a Restricted Subsidiary of Compton; or (b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, Compton or a Restricted Subsidiary of Compton; (4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption "-- Repurchase at the Option of Holders -- Asset Sales"; (5) any acquisition of assets solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of Compton; (6) any Investments received in compromise of obligations of such persons incurred in the ordinary course of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer; (7) Hedging Obligations and Oil and Gas Hedging Contracts; (8) Oil and Gas Investments; (9) loans or advances made (a) to any officer, director or employee of Compton or any of its Restricted Subsidiaries that are approved by a duly authorized officer, the proceeds of which are used solely to exercise stock options received pursuant to an employee stock option plan or other incentive plan, in a principal amount not to exceed the exercise price of such stock options and (b) to refinance loans, together with accrued interest thereon, made pursuant to this clause (9); PROVIDED such loans do not exceed US$5.0 million at any one time outstanding; and -91- (10) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (10) that are at the time outstanding not to exceed US$10.0 million. "PERMITTED LIENS" means, as of any date: (1) Liens on assets of Compton and any Subsidiary securing Indebtedness that constitutes Permitted Debt under Credit Facilities and Obligations in respect of such Indebtedness; (2) Liens in favor of Compton or any of the Guarantors; (3) Liens on property of a Person existing at the time such Person is amalgamated or merged with or into or consolidated with Compton or any Restricted Subsidiary of Compton; PROVIDED that such Liens were in existence prior to the contemplation of such amalgamation, merger or consolidation and do not extend to any assets other than those of the Person amalgamated or merged into or consolidated with Compton or the Subsidiary; (4) Liens securing Hedging Obligations and Oil and Gas Hedging Contracts that constitute Permitted Debt; (5) Liens securing the assets purchased by purchase money indebtedness which is Permitted Debt; (6) Liens to secure payment of royalties, revenue interests, net profits interests and preferential rights of purchase incurred in the ordinary course of business to the extent of the security interest in those underlying assets; (7) Liens for any judgments rendered that do not constitute an Event of Default; (8) Liens for any judgment rendered, or claim filed, against Compton or any Restricted Subsidiary which are being contested in good faith by appropriate proceedings that do not constitute an Event of Default if during such contestation a stay of enforcement of such judgment or claim is in effect; (9) Liens on property existing at the time of acquisition of the property by Compton or any Restricted Subsidiary of Compton, PROVIDED that such Liens were in existence prior to the contemplation of such acquisition; (10) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business; (11) Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clause (4) of the second paragraph of the covenant entitled "-- Certain Covenants -- Incurrence of Indebtedness and Issuance of Preferred Stock" covering only the assets acquired with such Indebtedness; (12) Liens existing on the date of the indenture; (13) Liens for taxes, assessments or other governmental charges or claims that are not yet due and payable or, if due and payable and delinquent, that are being contested by Compton or a Restricted Subsidiary in good faith by appropriate proceedings promptly instituted and diligently concluded, PROVIDED that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor; and (14) Liens in pipelines or pipeline facilities that arise by operation of law; (15) Liens arising in the ordinary course of business under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements, area -92- of mutual interest agreements and other agreements (including in respect of Production Payments), or arising by operation of law, that are customary in the Oil and Gas Business, and easements, rights of way or other similar rights in land in the ordinary course of business and that do not involve borrowing of money; (16) Liens reserved in oil and gas mineral leases for bonus or rental payments and for compliance with the terms of such leases; (17) Liens incurred in the ordinary course of business of Compton or any Subsidiary of Compton with respect to obligations that do not in the aggregate exceed US$5.0 million at any one time outstanding; and (18) Liens securing Permitted Refinancing Indebtedness in respect of Permitted Debt that was secured by Permitted Liens above and securing similar property. "PERMITTED REFINANCING INDEBTEDNESS" means any Indebtedness of Compton or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of Compton or any of its Restricted Subsidiaries (other than intercompany Indebtedness); PROVIDED that: (1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith); (2) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; (3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the notes, such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and is subordinated in right of payment to, the notes on terms at least as favorable to the Holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and (4) such Indebtedness is incurred either by Compton or by the Restricted Subsidiary who is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded. "PERSON" means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government, government body or agency or other entity. "PRODUCTION PAYMENTS" means Dollar-Denominated Production Payments and Volumetric Production Payments, collectively. "RESTRICTED INVESTMENT" means an Investment other than a Permitted Investment. "RESTRICTED SUBSIDIARY" of a Person means any Subsidiary of such Person that is not an Unrestricted Subsidiary. "SIGNIFICANT SUBSIDIARY" means any Subsidiary that would be a "significant subsidiary" as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date hereof. "STATED MATURITY" means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof. -93- "SUBSIDIARY" means, with respect to any specified Person: (1) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees of the corporation, association or other business entity is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and (2) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are that Person or one or more Subsidiaries of that Person (or any combination thereof). "UNRESTRICTED SUBSIDIARY" means any Subsidiary of Compton that is designated by the Board of Directors of Compton as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary: (1) has no Indebtedness other than Non-Recourse Debt; (2) is not party to any agreement, contract, arrangement or understanding with Compton or any Restricted Subsidiary of Compton unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to Compton or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of Compton; (3) is a Person with respect to which neither Compton nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person's financial condition or to cause such Person to achieve any specified levels of operating results; (4) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of Compton or any of its Restricted Subsidiaries; and (5) has at least one director on its Board of Directors that is not a director or executive officer of Compton or any of its Restricted Subsidiaries and has at least one executive officer that is not a director or executive officer of Compton or any of its Restricted Subsidiaries. Any designation of a Subsidiary of Compton as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of the Board Resolution giving effect to such designation and an officers' certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption "-- Certain Covenants -- Restricted Payments". If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of Compton as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption "-- Certain Covenants -- Incurrence of Indebtedness and Issuance of Preferred Stock", Compton will be in default of such covenant. The Board of Directors of Compton may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary; PROVIDED that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of Compton of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation will only be permitted if (1) such Indebtedness is permitted under the covenant described under the caption "-- Certain Covenants -- Incurrence of Indebtedness and Issuance of Preferred Stock", calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period; (2) no Default or Event of Default would be in existence following such designation; and (3) such Unrestricted Subsidiary becomes a Guarantor and executes a supplemental indenture and delivers an opinion of counsel reasonably satisfactory to the trustee within 10 Business Days of the date on which it is designated to the effect that such supplemental indenture has been duly authorized, executed and delivered and constitutes a legal, valid and binding agreement of such Subsidiary, enforceable against such Subsidiary in accordance with its terms. -94- "VOLUMETRIC PRODUCTION PAYMENTS" means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith. "VOTING STOCK" of any Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person. "WEIGHTED AVERAGE LIFE TO MATURITY" means, when applied to any Indebtedness at any date, the number of years obtained by dividing: (1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by (2) the then outstanding principal amount of such Indebtedness. -95- DESCRIPTION OF THE INITIAL NOTES The initial notes were issued and sold on May 8, 2002, in a private transaction that was exempt from the registration requirements of the Securities Act. The form and terms of the initial notes are the same as the form and terms of the exchange notes, except that: o the initial notes are not registered under the Securities Act and bear legends restricting their transfer, and o holders of initial notes have rights under a registration rights agreement which will terminate upon the consummation of the exchange offer. Please refer to the section of this prospectus entitled "Description of the Exchange Notes". BOOK-ENTRY, DELIVERY AND FORM Except as described below, we will initially issue the exchange notes in the form of one or more registered exchange notes in global form without coupons. We will deposit each global note on the date of the closing of this exchange offer with, or on behalf of, The Depository Trust Company in New York, New York, and register the exchange notes in the name of The Depository Trust Company or its nominee, or will leave these notes in the custody of the trustee. DEPOSITORY TRUST COMPANY PROCEDURES For your convenience, we are providing you with a description of the operations and procedures of The Depository Trust Company, the Euroclear System and Clearstream Banking, S.A. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We are not responsible for these operations and procedures and urge you to contact the system or its participants directly to discuss these matters. The Depository Trust Company has advised us that it is a limited-purpose trust company created to hold securities for its participating organizations and to facilitate the clearance and settlement of transactions in those securities between its participants through electronic book entry changes in the accounts of these participants. These direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and other organizations. Access to The Depository Trust Company's system is also indirectly available to other entities that clear through or maintain a direct or indirect, custodial relationship with a direct participant. The Depository Trust Company may hold securities beneficially owned by other persons only through its participants and the ownership interests and transfers of ownership interests of these other persons will be recorded only on the records of the participants and not on the records of The Depository Trust Company. The Depository Trust Company has also advised us that, in accordance with its procedures: (1) upon deposit of the global notes, it will credit the accounts of the direct participants with an interest in the global notes; and (2) it will maintain records of the ownership interests of these direct participants in the global notes and the transfer of ownership interests by and between direct participants. The Depository Trust Company will not maintain records of the ownership interests of, or the transfer of ownership interests by and between, indirect participants or other owners of beneficial interests in the global notes. Both direct and indirect participants must maintain their own records of ownership interests of, and the transfer of ownership interests by and between, indirect participants and other owners of beneficial interests in the global notes. -96- Investors in the global notes may hold their interests in the notes directly through The Depository Trust Company if they are direct participants in The Depository Trust Company or indirectly through organizations that are direct participants in The Depository Trust Company. Investors in the global notes may also hold their interests in the notes through Euroclear and Clearstream if they are direct participants in those systems or indirectly through organizations that are participants in those systems. Euroclear and Clearstream will hold omnibus positions in the global notes on behalf of the Euroclear participants and the Clearstream participants, respectively, through customers' securities accounts in Euroclear's and Clearstream's names on the books of their respective depositories, which are Morgan Guaranty Trust Company of New York, Brussels office, as operator of Euroclear, and Citibank, N.A. and The Chase Manhattan Bank, N.A., as operators of Clearstream. These depositories, in turn, will hold these positions in their names on the books of DTC. All interests in a global note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of The Depository Trust Company. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of those systems. The laws of some states require that some persons take physical delivery in definitive certificated form of the securities that they own. This may limit or curtail the ability to transfer beneficial interests in a global note to these persons. Because The Depository Trust Company can act only on behalf of direct participants, which in turn act on behalf of indirect participants and others, the ability of a person having a beneficial interest in a global note to pledge its interest to persons or entities that are not direct participants in The Depository Trust Company or to otherwise take actions in respect of its interest, may be affected by the lack of physical certificates evidencing the interests. Except as described below, owners of interests in the global notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or holders of these notes under the indenture for any purpose. Payments with respect to the principal of and interest on any notes represented by a global note registered in the name of The Depository Trust Company or its nominee on the applicable record date will be payable by the trustee to or at the direction of The Depository Trust Company or its nominee in its capacity as the registered holder of the global note representing these notes under the indenture. Under the terms of the indenture, we and the trustee will treat the person in whose names the notes are registered, including notes represented by global notes, as the owners of the notes for the purpose of receiving payments and for any and all other purposes whatsoever. Payments in respect of the principal and interest on global notes registered in the name of The Depository Trust Company or its nominee will be payable by the trustee to The Depository Trust Company or its nominee as the registered holder under the indenture. Consequently, none of the trustee or any of our agents, or the trustee's agents has or will have any responsibility or liability for: (1) any aspect of The Depository Trust Company's records or any direct or indirect participant's records relating to, or payments made on account of, beneficial ownership interests in the global notes or for maintaining, supervising or reviewing any of The Depository Trust Company's records or any direct or indirect participant's records relating to the beneficial ownership interests in any global note; or (2) any other matter relating to the actions and practices of The Depository Trust Company or any of its direct or indirect participants. The Depository Trust Company has advised us that its current practice, upon receipt of any payment in respect of securities such as the notes, including principal and interest, is to credit the accounts of the relevant participants with the payment on the payment date, in amounts proportionate to their respective holdings in the principal amount of beneficial interest in the security as shown on its records, unless it has reasons to believe that it will not receive payment on the payment date. Payments by the direct and indirect participants to the beneficial owners of interests in the global note will be governed by standing instructions and customary practice and will be the responsibility of the direct or indirect participants and will not be the responsibility of The Depository Trust Company, the trustee or us. Neither we nor the trustee will be liable for any delay by The Depository Trust Company or any direct or indirect participant in identifying the beneficial owners of the notes and the exchange agent and the trustee may conclusively rely on, and will be protected in relying on, instructions from The Depository Trust Company or its nominee for all purposes, including with respect to the registration and delivery, and the respective principal amounts, of the notes. -97- Transfers between participants in The Depository Trust Company will be effected in accordance with The Depository Trust Company's procedures, and will be settled in same day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures. Cross-market transfers between the participants in The Depository Trust Company, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through The Depository Trust Company in accordance with The Depository Trust Company's rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant global note in The Depository Trust Company, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to The Depository Trust Company. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream. The Depository Trust Company has advised us that it will take any action permitted to be taken by a holder of notes only at the direction of one or more participants to whose account The Depository Trust Company has credited the interests in the global notes and only in respect of the portion of the aggregate principal amount of the notes as to which the participant or participants has or have given that direction. However, if there is an event of default with respect to the notes, The Depository Trust Company reserves the right to exchange the global notes for legended notes in certificated form and to distribute them to its participants. Although The Depository Trust Company, Euroclear and Clearstream have agreed to these procedures to facilitate transfers of interests in the global notes among participants in The Depository Trust Company, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform these procedures and may discontinue them at any time. None of the trustee or any of our or the trustee's respective agents will have any responsibility for the performance by The Depository Trust Company, Euroclear or Clearstream or their direct or indirect participants of their respective obligations under the rules and procedures governing their operations. EXCHANGE OF BOOK-ENTRY NOTES FOR CERTIFICATED NOTES A global note will be exchangeable for definitive notes in registered certificated form if: (1) The Depository Trust Company notifies us that it is unwilling or unable to continue as depository for the global notes or if it ceases to be a clearing agency registered under the Exchange Act and we fail to appoint a successor depository within 120 days; (2) we, in our sole discretion, determine that the global notes should be exchanged for definitive notes; or (3) a default or an event of default under the indenture for the notes has occurred and is continuing. In all cases, certificated notes delivered in exchange for any global note or beneficial interests in a global note will be registered in the name, and issued in any approved denominations, requested by or on behalf of The Depository Trust Company, in accordance with its customary procedures. EXCHANGE OF CERTIFICATED NOTES FOR BOOK-ENTRY NOTES Initial notes issued in certificated form may be exchanged for beneficial interests in the global note. SAME DAY SETTLEMENT We expect that the interests in the global notes will be eligible to trade in The Depository Trust Company's Same-Day Funds Settlement System. As a result, secondary market trading activity in these interests will settle in immediately -98- available funds, subject in all cases to the rules and procedures of The Depository Trust Company and its participants. We expect that secondary trading in any certificated notes will also be settled in immediately available funds. Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a global note from a participant in The Depository Trust Company will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of The Depository Trust Company. The Depository Trust Company has advised us that cash received in Euroclear or Clearstream as a result of sales of interests in a global note by or through a Euroclear or Clearstream participant to a participant in The Depository Trust Company will be received with value on the settlement date of The Depository Trust Company but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following The Depository Trust Company's settlement date. PAYMENT The indenture requires that payments in respect of the notes represented by global notes, including principal and interest, be made by wire transfer of immediately available funds to the accounts specified by the holder of the global notes. With respect to notes in certificated form, we will make all payments of principal and interest on the notes at our office or agency maintained for that purpose within the city and state of New York. This office will initially be the office of the Paying Agent maintained for that purpose. At our option however, we may make these installments of interest by (1) check mailed to the holders of notes at their respective addresses provided in the register of holder of notes; or (2) transfer to an account maintained by the payee. MATERIAL INCOME TAX CONSIDERATIONS THE FOLLOWING SUMMARY IS OF A GENERAL NATURE ONLY AND IS NOT INTENDED TO BE, AND SHOULD NOT BE CONSTRUED TO BE, LEGAL OR TAX ADVICE TO ANY PROSPECTIVE INVESTOR AND NO REPRESENTATION WITH RESPECT TO THE TAX CONSEQUENCES TO ANY PARTICULAR INVESTOR IS MADE. ACCORDINGLY, PROSPECTIVE INVESTORS ARE URGED TO CONSULT WITH THEIR OWN TAX ADVISORS FOR ADVICE WITH RESPECT TO THE INCOME TAX CONSEQUENCES TO THEM, HAVING REGARD TO THEIR OWN PARTICULAR CIRCUMSTANCES, INCLUDING ANY CONSEQUENCES OF AN INVESTMENT IN THE NOTES OR THE EXCHANGE NOTES ARISING UNDER STATE, PROVINCIAL OR LOCAL TAX LAWS OR TAX LAWS OF JURISDICTIONS OUTSIDE THE UNITED STATES OR CANADA. CANADIAN FEDERAL INCOME TAX CONSIDERATIONS In the opinion of Fraser Milner Casgrain LLP, our Canadian legal counsel, the following is, as of the date of this prospectus, a fair and adequate opinion of the principal Canadian federal income tax consequences to a holder of the notes who is a non-resident of Canada. This opinion is based on the current provisions of the INCOME TAX ACT (Canada) and the regulations under that Act, counsel's understanding of the current published administrative practices of Canada Customs and Revenue Agency, and all specific proposals to amend the INCOME TAX ACT (Canada) and the regulations announced by the Minister of Finance prior to the date of this prospectus. This opinion does not otherwise take into account or anticipate changes in the law, whether by judicial, governmental or legislative decisions or action, nor does it take into account tax legislation or considerations of any province or territory of Canada or any jurisdiction other than Canada. This opinion assumes that, throughout the period the notes are outstanding, Compton will deal with the holders of notes (including DTC) at arm's length within the meaning of the INCOME Tax ACT (Canada), and that Compton will not, under any circumstances, be obliged to pay more than 25% of the aggregate principal amount of the notes within five years from the later of the date of issue or the date funds are advanced, except in the event of a default under the terms of the notes or of any agreement relating to the notes or if the terms of the notes or any such agreement become unlawful or are changed by legislative, judicial or administrative action. -99- The payment by Compton of interest or principal on the notes to a holder who is a non-resident of Canada and with whom Compton deals at arm's length within the meaning of the INCOME TAX ACT (Canada), at the time amounts are payable, in the case of interest, or at the time the payments are made, in the case of principal, will be exempt from Canadian withholding tax. For the purposes of the INCOME TAX ACT (Canada), related persons (as defined in the INCOME TAX ACT (Canada)) are deemed not to deal at arm's length and it is a question of fact whether persons not related to each other deal at arm's length. No other taxes on income (including taxable capital gains) will be payable under the INCOME TAX ACT (Canada) on the holding, redemption or disposition of the notes, or the receipt of interest on the notes by holders who are neither residents nor deemed to be residents of Canada for the purposes of the INCOME TAX ACT (Canada) and who do not use or hold and are not deemed by those laws to use or hold the notes in carrying on business in Canada for the purposes of the INCOME TAX ACT (Canada), except that in some circumstances holders who are non-resident insurers carrying on an insurance business in Canada and elsewhere may be subject to those taxes. U.S. FEDERAL INCOME TAX CONSIDERATIONS In the opinion of Paul, Weiss, Rifkind, Wharton & Garrison, our United States special counsel, the following is a summary of the material United States federal income tax consequences of the exchange of initial notes for exchange notes in accordance with the exchange offer and of the ownership and disposition of those exchange notes by United States persons (as defined below) who acquire the exchange notes in the exchange offer. This discussion assumes that United States persons hold the exchange notes as capital assets ("United States Holders") within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended (the "Code"). Furthermore, the following discussion does not purport to be a complete analysis of all of the potential United States federal income tax considerations that may be relevant to particular holders of exchange notes in light of their particular circumstances nor does it deal with persons that are subject to special tax rules, such as dealers in securities or currencies, financial institutions, insurance companies, tax-exempt organizations, persons holding the initial notes or exchange notes as part of a straddle, hedge or conversion transaction or a synthetic security or other integrated transaction, holders whose "functional currency" is not the United States dollar, and holders who are not United States Holders. In addition, the discussion below does not address tax consequences applicable to subsequent purchasers of the exchange notes nor does it address the tax consequences of the law of any state, locality or foreign jurisdiction. There can be no assurance that the United States Internal Revenue Service ("IRS") will take a similar view as to any of the tax consequences described in this summary. The following is based on currently existing provisions of the Code, existing and proposed Treasury regulations under the Code and current administrative rulings and court decisions. Everything listed in the previous sentence may change, possibly on a retroactive basis, and any change could affect the continuing validity of this discussion. PERSONS CONSIDERING THE PURCHASE, OWNERSHIP OR DISPOSITION OF NOTES ARE URGED TO CONSULT THEIR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL INCOME TAX CONSEQUENCES APPLICABLE TO THEM IN LIGHT OF THEIR PARTICULAR SITUATION AS WELL AS ANY CONSEQUENCES ARISING UNDER THE LAWS OF ANY STATE, LOCAL OR FOREIGN TAXING JURISDICTION. As used in this section, the term "United States person" means a beneficial owner of a note that is: (i) a citizen or resident of the United States, (ii) a corporation created or organized in or under the laws of the United States or any political subdivision of the United States; (iii) an estate the income of which is subject to United States federal income taxation regardless of its source; or (iv) a trust which is (A) subject to the supervision of a court within the United States and the control of a United States fiduciary as described in Section 7701(a)(30) of the Code; or (B) has made a valid election to be treated as a United States person. EXCHANGE OF INITIAL NOTES FOR EXCHANGE NOTES The exchange of initial notes for exchange notes pursuant to the exchange offer will not constitute a recognition event for U.S. federal income tax purposes. Consequently, (1) no gain or loss will be realized by a United States Holder upon receipt of an exchange note, (2) the holding period of the exchange note will include the holding period of the initial note exchanged for the exchange note, (3) the adjusted tax basis of the exchange note will be the same as the adjusted tax basis of the initial note exchanged therefor immediately before the exchange and (4) any market discount or bond premium (discussed below) applicable to the initial notes should carry over to the exchange notes. Further, the tax consequences of ownership and disposition of any exchange note should be the same as the tax consequences of ownership and disposition of an initial note. -100- PAYMENTS OF INTEREST Interest on a note will generally be taxable to a United States Holder as ordinary income at the time it is paid or accrued in accordance with the United States Holder's method of accounting for tax purposes. In addition to interest on the notes, a United States Holder will be required to include in income any additional amounts received pursuant to the section of this prospectus entitled "The Exchange Notes - Redemption for Changes in Canadian Withholding Taxes" and any taxes withheld from interest payments, notwithstanding that the United States Holder does not in fact receive such withheld taxes. A United States Holder may be entitled to claim a credit against its U.S. federal income tax liability, or a deduction in computing its U.S. federal taxable income, for Canadian income taxes withheld and paid over to the Canadian taxing authorities or for any of those taxes paid directly to the Canadian taxing authorities. The rules governing the foreign tax credit are complex. Investors are urged to consult their tax advisors regarding the availability of the foreign tax credit under their particular circumstances. Interest income on an exchange note generally will constitute foreign source income and generally will be considered "passive" income or "financial services" income (or, if Canadian withholding tax at a rate of 5% or more were to be imposed, as "high withholding tax interest"), which are treated separately from other types of income in computing the foreign tax credit allowable to United States Holders under the Code. MARKET DISCOUNT AND BOND PREMIUM If a United States Holder purchased an initial note after its initial issuance for an amount that is less than its principal amount, then, subject to a statutory de minimis rule, the difference generally will be treated as market discount. If a United States Holder exchanges an initial note, with respect to which there is market discount, for an exchange note pursuant to the exchange offer, the market discount applicable to the initial note should carry over to the exchange note so received. In that case, any partial principal payment on, or any gain realized on the sale, exchange, retirement or other disposition of, including dispositions which are nonrecognition transactions under certain provisions of the Code, the exchange note will be included in gross income and characterized as ordinary income to the extent of the market discount that (1) has not previously been included in income and (2) is treated as having accrued on the exchange note prior to the payment or disposition. In addition, to the extent that the exchange notes are acquired with market discount, a United States Holder generally may be required to defer a portion of the interest expense on indebtedness incurred or continued to purchase or carry such notes. Market discount generally accrues on a straight-line basis over the remaining term of the exchange note. A taxpayer may elect, however, to accrue market discount on a constant yield basis. Further, a United States Holder may elect to include market discount in gross income currently as it accrues. If such an election is made, the preceding rules relating to the recognition of market discount and deferral of interest expense will not apply. An election made to include market discount in gross income as it accrues will apply to all debt instruments acquired by the United States Holder on or after the first day of the taxable year to which the election applies and may be revoked only with the consent of the IRS. If a United States Holder purchased an initial note for an amount in excess of principal, the excess will be treated as bond premium. If a United States Holder exchanges an initial note, with respect to which there is bond premium, for an exchange note pursuant to the exchange offer, the bond premium applicable to the initial note should carry over to the exchange note so received. In general, a United States Holder may elect to amortize bond premium over the remaining term of the exchange note on a constant yield method. An election to amortize bond premium applies to all taxable debt instruments held at the beginning of the first taxable year to which the election applies and thereafter acquired by the United States Holder and may be revoked only with the consent of the IRS. SALE, EXCHANGE AND REDEMPTION OF NOTES Upon the sale, exchange or redemption of an exchange note, a United States Holder will recognize gain or loss equal to the difference between the amount realized upon the sale, exchange or redemption (less any accrued interest, which will be taxable as ordinary interest income) and the United States Holder's adjusted tax basis in the exchange note. A United States Holder's adjusted tax basis in a note generally will be the adjusted tax basis of such holder in the initial note that was exchanged therefor, increased by market discount, if any, that is included in such holder's income and reduced (but not below zero) by any amortized bond premium which a United States Holder has elected to deduct from taxable income on an annual basis. If a United States Holder exchanges an initial note, with respect to which there is market discount or bond premium, for an exchange note pursuant to the exchange offer, the market discount or bond premium applicable to the initial note should carry over to the exchange note so received. In general, market discount on an initial note is the excess, if any, of the principal amount of an initial note over the United States Holder's tax basis in such initial note at the time of acquisition -101- (unless the amount of such excess is less than a specified DE MINIMIS amount, in which case market discount is considered to be zero). In general, bond premium on an initial note equals the excess, if any, of the purchase price of the initial note over the amount payable at maturity of the initial note (other than stated interest thereon). Except as provided above (see "Market Discount and Bond Premium"), gain or loss realized on the sale, exchange or redemption of an exchange note will be capital gain or loss and will be long-term capital gain or loss if at the time of sale, exchange or retirement the exchange note has been held for more than one year. Under current law, net capital gains of individuals are, under some circumstances, taxed at lower rates than items of ordinary income. The deductibility of capital losses is subject to limitations. If the United States Holder is a U.S. resident (as defined in section 865 of the Code), gains realized upon disposition of an exchange note by such United States Holder generally will be U.S. source income, and disposition losses generally will be allocated to reduce U.S. source income. INFORMATION REPORTING AND BACKUP WITHHOLDING In general, information reporting requirements will apply to certain payments of principal and interest on a note and to the payments of proceeds of the sale of an exchange note made to United States Holders other than certain exempt recipients (such as corporations). A United States Holder that is not an exempt recipient will generally be subject to backup withholding with respect to such payments (currently at a rate of 30%, declining until 2006 to 28%, which rate will remain constant until replaced by a 31% rate beginning in 2011) unless the United States Holder provides an accurate taxpayer identification number and otherwise complies with applicable requirements of the backup withholding rules. Any amounts withheld under the backup withholding rules will be allowed as a credit against the United States Holder's U.S. federal income tax liability or refundable to the extent that it exceeds such liability. A United States Holder who does not provide a correct taxpayer identification number may be subject to penalties imposed by the IRS. THE U.S. FEDERAL INCOME TAX DISCUSSION PROVIDED ABOVE IS INCLUDED FOR GENERAL INFORMATION ONLY AND MAY OR MAY NOT APPLY TO YOU DEPENDING UPON YOUR PARTICULAR SITUATION. YOU ARE URGED TO CONSULT YOUR OWN TAX ADVISOR WITH RESPECT TO THE TAX CONSEQUENCES TO YOU OF OWNING, HOLDING, AND DISPOSING OF A NOTE, INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, FOREIGN, AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN FEDERAL OR OTHER TAX LAWS. PLAN OF DISTRIBUTION Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer in exchange for initial notes acquired by such broker-dealer as a result of market making or other trading activities maybe deemed to be an "underwriter" within the meaning of the Securities Act and, therefore, must deliver a prospectus meeting the requirements of the Securities Act in connection with any resales, offers to resell or other transfers of the exchange notes received by it in connection with the exchange offer. Accordingly, each such broker-dealer must acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such exchange notes. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for initial notes where such initial notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the expiration of this exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit of any such resale of exchange -102- notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. LEGAL MATTERS Legal matters in connection with the exchange offer will be passed upon for us by Paul, Weiss, Rifkind, Wharton & Garrison, New York, New York (concerning matters of U.S. law) and Fraser Milner Casgrain LLP, Calgary, Alberta (concerning matters of Canadian law). The partners of Paul, Weiss, Rifkind, Wharton & Garrison beneficially own less than 1% of our outstanding shares and the partners of Fraser Milner Casgrain LLP beneficially own less than 1% of our outstanding shares. INDEPENDENT PETROLEUM ENGINEERS Information about our estimated proved reserves and the future net cash flows attributable to these reserves as of December 31, 1999 and 2000 was prepared or reviewed by Outtrim Szabo Associates Ltd. The reserve information as of December 31, 2001 was prepared by Outtrim Szabo Associates Ltd. INDEPENDENT ACCOUNTANTS The financial statements of Compton, as of December 31, 1999, 2000 and 2001 and for each of the years in the periods ended December 31, 1999, 2000 and 2001, included in this prospectus have been audited by Grant Thornton LLP, Chartered Accountants, as stated in their report appearing herein. WHERE YOU CAN FIND MORE INFORMATION We have filed a registration statement on Form F-4 with the Commission covering the exchange notes. This prospectus is part or our registration statement. For further information about us and the exchange notes, you should refer to our registration statement and its exhibits. This prospectus summarizes material provisions of contracts and other documents to which we refer you. Since the prospectus might not contain all of the information that you might find important, you should review the full text of these documents. We have included copies of these documents as exhibits to our registration statement. We file information, such as periodic reports and financial information, with the Canadian Securities Administrators, which may be accessed at www.sedar.com. Upon filing of this registration statement, we will be subject to the periodic reporting and other informational requirements of the Exchange Act, and accordingly we will file reports and other information with the Commission. Copies of such reports and other information will be available for inspection and can be copied at the public reference facilities maintained by the Commission. Copies of these materials may also be obtained by mail at prescribed rates from the Public Reference Section of the Commission, 450 Fifth Street, N.W., Washington, D.C. 20549 or by calling the Commission at l-800-SEC-0330. Our filings with the SEC will also be available to the public from commercial document retrieval services and at the SEC's web site at "http://www.sec.gov". However, we are a "foreign private issuer" as defined in Rule 405 of the Securities Act, and therefore are not required to comply with Exchange Act provisions regarding proxy statements and short swing profit disclosure. Anyone who receives a copy of this prospectus may obtain a copy of the indenture without charge by writing to: Compton Petroleum Corporation, Suite 3300, 425--1st Street S.W., Calgary, Alberta, Canada, T2P 3L8, Attn: Corporate Secretary. -103- In the indenture for the notes we have agreed that, whether or not we are required to do so by the rules and regulations of the Commission, for so long as any of the notes are outstanding, we will furnish the trustee and holders of notes with: o all quarterly and annual financial information that would be required to be contained in a submission to the Commission on Forms 40-F and 6-K if we were required to file or furnish such forms; o a report on the financial information by our certified independent accountants, with respect to our annual financial information only; and o all reports that would be required to be filed with the Commission on Form 6-K if we were required to file such reports. In addition, for so long as any of the initial notes remain outstanding and are "restricted securities" within the meaning of Rule l44(a)(3) of the Securities Act, we have agreed to make available to any holder or beneficial owner of the notes or any prospective purchaser of the notes designated by a holder or beneficial owner of the notes, in connection with any sale of the notes, the information required by Rule l44A(d)(4) under the Securities Act, unless we furnish information to the Commission in accordance with Rule 12g-3-2(b) or under Section 13 or 15(d) of the Exchange Act. -104- FINANCIAL STATEMENTS INDEX FINANCIAL STATEMENTS OF COMPTON PETROLEUM CORPORATION Report of Independent Auditors........................................ F-2 Consolidated Balance Sheets-- December 31, 2000 and 2001 and June 30, 2002.............................................................. F-3 Consolidated Statements of Earnings and Retained Earnings-- Years Ended December 31, 1999, 2000 and 2001 and Six Months Ended June 30, 2001 and 2002............................... F-4 Consolidated Statements of Cash Flow -- Years Ended December 31, 1999, 2000 and 2001 and Six Months Ended June 30, 2001 and 2002............................................ F-5 Notes to the Consolidated Financial Statements........................ F-6 F-1 INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Compton Petroleum Corporation We have audited the consolidated balance sheets of Compton Petroleum Corporation as at December 31, 2001 and 2000 and the consolidated statements of earnings and retained earnings and cash flow for each of the years in the three year period ended December 31, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in Canada and the United States of America. These standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosure in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2001 and 2000 and the results of its operations and cash flow for each of the years in the three year period ended December 31, 2001 in accordance with accounting principles generally accepted in Canada. Calgary, Alberta (SIGNED) "GRANT THORNTON LLP" March 11, 2002, except for Chartered Accountants Note 16 which is as of May 8, 2002 COMMENTS BY AUDITOR FOR U.S. READERS ON CANADA-U.S. REPORTING DIFFERENCES In the United States of America, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the Company's financial statements, such as the changes described in Note 3 to the consolidated financial statements. Our report to the shareholders dated March 11, 2002 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors' Report when the change is properly accounted for and adequately disclosed in the consolidated financial statements. Calgary, Alberta (SIGNED) "GRANT THORNTON LLP" Canada Chartered Accountants March 11, 2002 F-2 ================================================================================ COMPTON PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS (thousands of Canadian dollars) AS AT AS AT DECEMBER 31, JUNE 30, ----------------------- 2002 2001 2000 -------------------------------------------------------------------------------- (unaudited) ASSETS Current Cash $ 640 $ 5,052 $ -- Accounts receivable and other 78,935 82,001 81,375 -------- -------- -------- 79,575 87,053 81,375 Deferred financing charges 14,349 -- -- Property and equipment (Note 5) 623,572 606,920 442,897 -------- -------- -------- $717,496 $693,973 $524,272 ======== ======== ======== LIABILITIES Current Accounts payable $ 42,773 $ 64,903 $ 51,439 Long-term debt (Note 6) 250,586 230,000 183,376 Capital lease obligations (Note 7) 394 449 -- Future income taxes (Notes 3 and 12) 188,643 179,192 130,302 Future site restoration (Note 8) 1,930 1,569 1,359 -------- -------- -------- 484,326 476,113 366,476 -------- -------- -------- SHAREHOLDERS' EQUITY Capital stock (Note 9) 118,293 116,572 94,472 Retained earnings 114,877 101,288 63,324 -------- -------- -------- 233,170 217,860 157,796 -------- -------- -------- $717,496 $693,973 $524,272 ======== ======== ======== Commitments and contingencies (Note 15) Subsequent events (Note 16) See accompanying notes to the consolidated financial statements. F-3 ================================================================================ COMPTON PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF EARNINGS AND RETAINED EARNINGS (thousands of Canadian dollars, except per share data)
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ---------------------------- -------------------------------------------- 2002 2001 2001 2000 1999 (restated Note 3b) -------------------------------------------------------------------------------------------------------------------- (unaudited) REVENUE Oil and gas revenues $ 96,566 $ 153,612 $ 244,970 $ 213,376 $ 97,016 Royalties, net (21,142) (36,072) (55,919) (44,695) (16,105) ------------ ------------- ------------ ------------ ------------ 75,424 117,540 189,051 168,681 80,911 ------------ ------------- ------------ ------------ ------------ EXPENSES Operating 21,855 18,508 40,222 31,571 20,521 General and administrative 4,316 3,692 6,302 5,915 4,222 Interest 6,560 6,284 12,863 12,772 6,939 Unrealized foreign exchange gain (8,465) -- -- -- -- Depletion and depreciation 26,427 23,789 50,450 41,767 20,160 ------------ ------------- ------------ ------------ ------------ 50,693 52,273 109,837 92,025 51,842 ------------ ------------- ------------ ------------ ------------ EARNINGS BEFORE TAXES 24,731 65,267 79,214 76,656 29,069 ------------ ------------- ------------ ------------ ------------ TAXES Future income taxes (Note 12) 9,294 17,224 22,248 35,707 11,782 Capital taxes 939 548 1,330 890 199 ------------ ------------- ------------ ------------ ------------ 10,233 17,772 23,578 36,597 11,981 ------------ ------------- ------------ ------------ ------------ NET EARNINGS 14,498 47,495 55,636 40,059 17,088 RETAINED EARNINGS, beginning of period 101,288 63,324 63,324 27,197 10,735 ------------ ------------- ------------ ------------ ------------ 115,786 110,819 118,960 67,256 27,823 Change in accounting policies (Note 3) -- (3,585) (3,585) (380) -- Premium on redemption of shares (Note 9) (909) (10,406) (14,087) (3,552) (626) ------------ ------------- ------------ ------------ ------------ RETAINED EARNINGS, end of period $ 114,877 $ 96,828 $ 101,288 $ 63,324 $ 27,197 ============ ============= ============ ============ ============ EARNINGS PER SHARE Basic $ 0.13 $ 0.44 $ 0.51 $ 0.37 $ 0.18 ============ ============= ============ ============ ============ Diluted (Note 11) $ 0.12 $ 0.42 $ 0.48 $ 0.36 $ 0.17 ============ ============= ============ ============ ============
See accompanying notes to the consolidated financial statements. F-4 ================================================================================ COMPTON PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOW (thousands of Canadian dollars)
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ------------------------- ---------------------------------- 2002 2001 2001 2000 1999 (restated Note 3b) -------------------------------------------------------------------------------------------------------- (unaudited) CASH DERIVED FROM (APPLIED TO) OPERATING Net earnings $ 14,498 $ 47,495 $ 55,636 $ 40,059 $ 17,088 Items not affecting cash Depletion and depreciation 26,427 23,789 50,450 41,767 20,160 Future income taxes 9,294 17,224 22,248 35,707 11,782 Amortization of deferred charges 251 -- -- -- -- Unrealized foreign exchange gain (8,465) -- -- -- -- --------- --------- --------- --------- --------- Cash flow from operations 42,005 88,508 128,334 117,533 49,030 Change in non-cash working capital (Note 14) 9,097 3,941 (7,266) (13,346) (11,201) --------- --------- --------- --------- --------- 51,102 92,449 121,068 104,187 37,829 --------- --------- --------- --------- --------- FINANCING Change in long-term debt (230,000) (1,376) 36,304 23,662 41,205 Capital lease obligations (55) -- (38) -- -- Issuance of Senior notes 259,050 -- -- -- -- Deferred financing charges (14,435) -- -- -- -- Proceeds from share issues, net 814 1,464 41,558 11,844 18,126 Redemption of common shares (1,234) (12,958) (17,774) (5,564) (1,187) --------- --------- --------- --------- --------- 14,140 (12,870) 60,050 29,942 58,144 --------- --------- --------- --------- --------- Cash available for investing activities 65,242 79,579 181,118 134,129 95,973 --------- --------- --------- --------- --------- INVESTING Property and equipment additions (41,392) (78,224) (147,993) (118,153) (71,216) Corporate acquisitions (Note 4) -- -- (29,669) -- (49,833) Dispositions (acquisitions), net -- -- (10,243) (241) 15,351 Site restoration (99) (69) (473) (368) (507) Change in non-cash working capital (Note 14) (28,163) 56 12,312 (307) (4,828) --------- --------- --------- --------- --------- (69,654) (78,237) (176,066) (119,069) (111,033) --------- --------- --------- --------- --------- CHANGE IN CASH (4,412) 1,342 5,052 15,060 (15,060) CASH, BEGINNING OF PERIOD 5,052 -- -- (15,060) -- --------- --------- --------- --------- --------- CASH, END OF PERIOD $ 640 $ 1,342 $ 5,052 $ -- $ (15,060) ========= ========= ========= ========= =========
See accompanying notes to the consolidated financial statements. F-5 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 1. NATURE OF OPERATIONS The Company is engaged primarily in the exploration for and production of petroleum and natural gas reserves in a single cost centre being the Western Canadian Sedimentary Basin. 2. SIGNIFICANT ACCOUNTING POLICIES a) BASIS OF PRESENTATION The consolidated financial statements of the Company have been prepared in accordance with accounting principles generally accepted in Canada within the framework of the accounting policies summarized below. Accounting principles generally accepted in Canada vary in certain significant respects from accounting principles generally accepted in the United States of America. The application of the latter would have affected the determination of net income for the six month period ended June 30, 2002 and 2001 and each of the years ended December 31, 2001, 2000 and 1999 and the determination of shareholders' equity and financial position as at June 30, 2002 and December 31, 2001 and 2000 to the extent summarized in Note 17. Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries from the respective dates of acquisition. Inter-company transactions and balances are eliminated upon consolidation. b) PETROLEUM AND NATURAL GAS PROPERTIES i) Capitalized costs The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under this method all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Costs include lease acquisition costs, geological and geophysical expenses, interest on debt directly related to certain acquisitions, and costs of drilling both productive and non-productive wells. Proceeds from the sale of properties are applied against capitalized costs, without any gain or loss being realized, unless such sale would significantly alter the rate of depletion and depreciation. ii) Depletion and depreciation Depletion of exploration and development costs and depreciation of production equipment is provided using the unit-of-production method based upon estimated proved petroleum and natural gas reserves. The costs of significant undeveloped properties are excluded from costs subject to depletion. For depletion and depreciation purposes, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. Depreciation of office equipment is provided for on a declining-balance basis at 20% per annum. F-6 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) iii) Ceiling test In applying the full cost method, the Company calculates a ceiling test whereby the carrying value of petroleum and natural gas properties and production equipment, net of recorded future income taxes and the accumulated provision for site restoration and abandonment costs, is compared annually to an estimate of future net cash flow from the production of proved reserves. Net cash flow is estimated using year end prices, less estimated future general and administrative expenses, financing costs and income taxes. Should this comparison indicate an excess carrying value, the excess is charged against earnings as additional depletion and depreciation. iv) Future site restoration and abandonment costs Estimated costs of future site restoration and abandonments, net of recoveries, are provided for over the life of proved reserves on a unit-of-production basis. An annual provision is recorded as additional depletion and depreciation. Costs are based on engineering estimates of the anticipated method and extent of site restoration in accordance with current legislation, industry practices and costs. The accumulated provision is reflected as a non-current liability and actual expenditures are charged against the accumulated provision when incurred. c) FINANCIAL INSTRUMENTS Financial instruments consist mainly of accounts receivable and other, accounts payable and long-term debt. There are no significant differences between the carrying value of these financial instruments and their estimated fair value. From time to time, the Company may employ financial instruments to manage exposure related to Canada/U.S. exchange rates and commodity prices associated with the sale of the Company's production. Gains and losses on these financial instruments, employed as exchange rate and commodity price hedges, are included in revenues upon sale of the related hedged production. d) JOINT OPERATIONS Certain petroleum and natural gas activities are conducted jointly with others. These consolidated financial statements reflect only the Company's proportionate interest in such activities. e) FLOW-THROUGH SHARES Resource expenditure deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. Future income tax liability is increased and capital stock is reduced by the estimated tax benefits transferred to shareholders. F-7 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) f) PER SHARE AMOUNTS Basic earnings per common share is computed by dividing earnings by the weighted average number of common shares outstanding for the year. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares were exercised or converted to common shares. g) USE OF ESTIMATES The preparation of consolidated financial statements in accordance with accounting principles generally accepted in Canada requires management to make assumptions and estimates that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from and affect the results reported in these consolidated financial statements. h) HEDGING ACTIVITIES Settlement of crude oil and natural gas swap agreements, which have been arranged as a hedge against commodity price, are reflected in product revenues at the time of sale of the related hedged production. i) INCOME TAXES Income taxes are recorded using the liability method of tax allocation. Future income taxes are calculated based on temporary differences arising from the difference between the tax basis of an asset or liability and its carrying value using tax rates anticipated to apply in the periods when the temporary differences are expected to reverse. j) REVENUE RECOGNITION Revenue associated with the production and sales of crude oil, natural gas and natural gas liquids owned by the Company are recognized when title passes from the Company to its customer. k) STOCK-BASED COMPENSATION PLANS The Company has a stock-based compensation plan, which includes stock options and an employee stock savings plan. Consideration received from employees or directors on the exercise of stock options under the stock option plan is recorded as share capital. Compensation costs have not been recognized for fixed share options granted to employees and directors. The Company matches employee contributions to the stock savings plan and these cash payments are recorded as compensation expense. l) DEFERRED FINANCING CHARGES Financing costs related to the issuance of the senior term notes and syndicated senior credit facility have been deferred and are amortized over the term of the respective financing vehicles on a straight-line basis. F-8 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 2. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) m) FOREIGN CURRENCY TRANSLATION Long-term debt payable in U.S. dollars is translated into Canadian dollars at the period-end exchange rate, with any resulting adjustment recorded in the Consolidated Statement of Earnings and Retained Earnings. n) DIVIDEND POLICY 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. o) RECLASSIFICATION Certain prior year amounts in the Consolidated Statements of Cash Flow for 1999 have been reclassified to conform to current year presentation. 3. CHANGES IN ACCOUNTING POLICIES a) Effective January 1, 2002, the Company adopted the Canadian Institute of Chartered Accountants (CICA) amended accounting standard with respect to accounting for foreign currency translation. As a result of adopting this amended standard, gains or losses on the translation of long-term debt denominated in U.S. dollars are no longer deferred and amortized over the term of the debt, but are recognized in earnings. The adoption of this amended standard resulted in an unrealized foreign exchange gain of $8.5 million in the second quarter of 2002. This amended standard affects the Company's accounting for its U.S. denominated senior term notes due May 15, 2009 (refer to Note 6). b) During the fourth quarter of 2001, the Company early adopted the new recommendations of the CICA with respect to accounting for stock based compensation. The Company has adopted this accounting policy retroactively, without restating the financial statements of prior periods. Effective January 1, 2001, the Company recorded a reduction in retained earnings of $3.6 million, an increase in accounts payable of $6.2 million and a decrease in future income tax liability of $2.6 million. Due to the adoption of these recommendations, the consolidated financial statements for the six months ended June 30, 2001, have been restated from those originally reported by the Company. As a result, the Company recorded an increase to net earnings of $74 thousand with nil effect to the Company's basic and diluted earnings per share. c) Effective January 1, 2000, the Company adopted the new recommendations of the CICA with respect to accounting for future income taxes. Under the new recommendations the liability method of tax allocation is used, which is based upon the difference between financial and tax bases of assets and liabilities. F-9 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 3. CHANGES IN ACCOUNTING POLICIES (CONTINUED) The Company has adopted this change in accounting policy retroactively, without restating the financial statements of prior periods. As a result, the Company recorded a reduction in retained earnings of $0.4 million, an increase in property and equipment of $68.1 million and an increase in the future income tax liability of $68.5 million, as at January 1, 2000. d) The CICA approved a new standard for the compilation and disclosure of per share amounts. In 2000, the Company retroactively adopted the new standard. Under this standard, the treasury stock method is used instead of the imputed earnings method to determine the dilutive effect of stock options and other dilutive instruments. Prior period diluted earnings per share has been restated for this change in accounting policy. If the imputed earnings method had been used to calculate this amount, the reported amounts would have been for the year ended December 31, 2000 - $0.35 per share (1999 - $0.16 per share). 4. ACQUISITIONS Effective July 16, 2001, the Company acquired all of the issued and outstanding shares of Hornet Energy Ltd. ("Hornet"), a public company involved in the exploration, development and production of oil and natural gas primarily in southern Alberta. The acquisition has been accounted for by the purchase method of accounting and the consolidated financial statements include the results of operations from date of acquisition. The fair value of the assets acquired is as follows: NET ASSETS ACQUIRED Property and equipment $ 54,276 Future income taxes (12,236) ------------ 42,040 Working capital deficiency (1,460) Long-term debt (10,320) Capital lease obligations (591) ------------ $ 29,669 ============ CONSIDERATION Cash $ 29,134 Transaction costs 535 ------------ $ 29,669 ============ 1999 - COPAREX CANADA LTD. On December 1, 1999 the Company acquired all of the issued and outstanding shares of Coparex Canada Ltd. ("Coparex"), for cash consideration of $49.8 million. Coparex, a privately owned corporation, was engaged in oil and gas exploration activities primarily in Alberta. The transaction has been accounted for by the purchase method and the consolidated financial statements include the results of the operations from date of acquisition. The fair value of the assets acquired is as follows: F-10 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 4. ACQUISITIONS (CONTINUED) NET ASSETS ACQUIRED Property and equipment Oil and gas reserves and facilities $ 64,421 Undeveloped lands 10,173 ------------ 74,594 Working capital 132 Long-term debt (24,893) ------------ $ 49,833 ============ CONSIDERATION Cash $ 49,368 Transaction costs 465 ------------ $ 49,833 ============ The following table reflects unaudited pro forma combined results of operations of the Company and the above acquisitions on the basis that the acquisitions had taken place at the beginning of the fiscal period for each of the periods presented: 2001 2000 1999 ---- ---- ---- Revenue, net of royalties $ 195,593 $ 176,777 $ 101,947 Net earnings 52,111 39,958 17,397 Earnings per share Basic 0.47 0.37 0.18 Diluted 0.45 0.36 0.17 F-11 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 5. PROPERTY AND EQUIPMENT
DECEMBER 31, JUNE 30, ------------------------- 2002 2001 2000 ---- ---- ---- Exploration and development costs $ 667,899 $ 635,508 $ 455,565 Accumulated depletion (132,187) (109,091) (64,058) --------- --------- --------- 535,712 526,417 391,507 --------- --------- --------- Production equipment and processing facilities 98,204 88,727 55,529 Office equipment 3,609 2,808 2,154 --------- --------- --------- 101,813 91,535 57,683 Accumulated depreciation (13,953) (11,032) (6,293) --------- --------- --------- 87,860 80,503 51,390 --------- --------- --------- $ 623,572 $ 606,920 $ 442,897 ========= ========= =========
The Company does not capitalize any portion of its general and administrative expenses. During the six months ended June 30, 2002 - nil (six months ended June 30, 2001 - nil; year ended December 31, 2001 - nil; 2000 - $0.7 million; 1999 - $0.2 million) of interest expense associated with certain property acquisitions and processing facilities was capitalized. Future capital expenditures of $33.0 million (2000 - $37.1 million; 1999 - $26.7 million), as estimated by independent engineers, relating to the development of proved non-producing reserves have been included in costs subject to depletion, and undeveloped properties with a cost at June 30, 2002 - $163.0 million (June 30, 2001 - $135.6 million; December 31, 2001 of $161.0 million; 2000 - $98.8 million; 1999 - $55.6 million), included in exploration and development costs, have not been subject to depletion. 6. LONG-TERM DEBT DECEMBER 31, JUNE 30, ------------------- 2002 2001 2000 ---- ---- ---- Senior term notes (US$ 165,000,000) $250,586 $ -- $ -- Prime rate advances -- -- 8,376 Banker's Acceptances -- 230,000 175,000 -------- -------- -------- $250,586 $230,000 $183,376 ======== ======== ======== a) SENIOR TERM NOTES On May 8, 2002, the Company completed an offering of US$165 million senior notes bearing interest at 9.90 percent with principal repayable on May 15, 2009. Interest is payable on May 15 and November 15 of each year, beginning on November 15, 2002. The Company used the net proceeds to repay its entire existing bank indebtedness and for general corporate purposes. The senior notes are unsecured. F-12 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 6. LONG-TERM DEBT (CONTINUED) Concurrent with the closing of the senior notes offering, the Company entered into interest rate swap arrangements with its banking syndicate whereby interest paid by the Company, relating to the senior notes. The US$165 million principal amount will be based upon the 90 day Bankers' Acceptance rate plus 4.85 percent. This arrangement resulted in an effective interest rate of 7.40 percent during the second quarter of 2002. b) CREDIT FACILITIES As at June 30, 2002, the Company had authorized syndicated senior credit facilities, with Canadian financial institutions, in the amount of $168 million (2001 - $240 million). The senior credit facilities consist of a $158 million (2001 - $230 million) extendible revolving credit facility and a $10 million (2001 - $10 million) working capital facility. As a result of the Company's US$165 million senior notes issuance, completed May 8, 2002, the Company's senior credit facilities were adjusted to $168 million. Advances under the facilities can be drawn in either Canadian or U.S. funds. The facilities bear interest at the lenders' prime lending rate or at the Bankers' Acceptance rate or LIBOR plus a margin based on the ratio of total consolidated debt to cash flow, currently set at 0.625 percent, 1.625 percent and 1.625 percent, respectively. These facilities mature on July 9, 2003 and are secured by a fixed and floating charge debenture in the amount of $325 million covering all of the Company's assets and undertakings. 7. CAPITAL LEASES Certain leases relating to gas processing equipment, having costs in the aggregate of $601 thousand and accumulated depreciation of $36 thousand, are classified as capital leases and are included in property and equipment. These capital lease obligations were acquired as part of the Hornet acquisition referred to in Note 4. Each lease contains an option to purchase and has an implicit interest rate of 7.8 percent to 8.8 percent. Excluded from the following future capital lease payment obligations is interest in the amount of $92 thousand. December 31, 2001 ---- 2002 $ 104 2003 323 2004 36 2005 38 2006 52 ------------ 553 Less: current portion, included in accounts payable 104 ------------ $ 449 ============ F-13 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 8. SITE RESTORATION AND ABANDONMENTS At June 30, 2002 total future removal and site restoration costs to be accrued over the life of the remaining proved reserves were estimated, net of recoveries, at $8.8 million (December 31, 2001 - $8.5 million; December 31, 2000 - $5.4 million) of which $1.9 million (December 31, 2001 - $1.6 million; December 31, 2000 - $1.4 million) have been accrued. This estimate is subject to change based on amendments to environmental laws and as new information concerning operations becomes available. 9. CAPITAL STOCK a) AUTHORIZED: Unlimited number of common shares Unlimited number of preferred shares, issuable in series b) ISSUED AND OUTSTANDING: SIX MONTHS ENDED JUNE 30, 2002 ----------------------------- NUMBER OF SHARES AMOUNT --------- ------ COMMON SHARES Balance, beginning of period 113,105,450 $ 116,572 Issued for property 350,000 1,225 Issued for cash on exercise of options 358,099 822 Repurchased for cash (315,400) (326) ------------ ------------ Balance, end of period 113,498,149 $ 118,293 ============ ============
YEARS ENDED DECEMBER 31, ------------------------------------------------------------ 2001 2000 -------------------------- --------------------------- NUMBER NUMBER OF SHARES AMOUNT OF SHARES AMOUNT --------- ------ --------- ------ COMMON SHARES Balance, beginning of year 108,783,649 $ 94,472 108,047,882 $ 89,505 Issued for cash, net 7,345,604 22,964 3,075,100 6,825 Issued for property 241,997 1,285 30,000 78 Issued for cash on exercise of warrants 625,616 1,095 -- -- Issued for cash on exercise of options 314,584 443 56,667 76 Repurchased for cash (4,206,000) (3,687) (2,426,000) (2,012) ------------ ------------ ------------ ------------ Balance, end of year 113,105,450 $ 116,572 108,783,649 $ 94,472 ============ ============ ============ ============
F-14 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 9. CAPITAL STOCK (CONTINUED) During 2001, common shares issued for cash include 7,345,604 (2000 - 3,075,100) common shares issued on a flow-through basis. Under the terms of the year 2001 flow-through agreements, the Company is required to expend $41.8 million on qualifying oil and natural gas expenditures prior to December 31, 2002. As at December 31, 2001, the Company had incurred qualifying expenditures in the amount of $16.2 million. During the first six months of 2002, the Company repurchased for cancellation 315,400 common shares at an average price of $3.91 per share (2001 - 4,206,000 shares at an average price of $4.23 per share; 2000 - 2,426,000 shares at an average price of $2.29 per share), pursuant to a normal course issuer bid. The excess of the purchase price over book value has been charged to retained earnings. c) OUTSTANDING WARRANTS In 1998, in conjunction with the disposition of certain facilities, the Company issued share purchase warrants to a third party, which entitled the holder to acquire 3,000,000 common shares of the Company. As at December 31, 2001, nil (2000 - 1,000,000; 1999 - 1,000,000) warrants were outstanding at an exercise price of $1.75 per share. The warrants were exercisable on the basis of 10,000 warrants for each $250,000 paid to the Company as an incentive fee under the terms of the disposition. In 2001, a total of 625,616 warrants were exercised for gross proceeds of $1.1 million. The remaining warrants were cancelled. d) SHAREHOLDER RIGHTS PLAN The Company has a Shareholder Rights Plan to ensure all shareholders are treated fairly in the event of a take-over offer or other acquisition of control of the Company. Pursuant to the Plan, the Board of Directors authorized and declared the distribution of one Right in respect of each common share outstanding. In the event that an acquisition of 20% or more of the Company's shares is completed and the acquisition is not a permitted bid, as defined by the Plan, each Right will permit the holder to acquire, at the exercise price of $50.00, such number of common shares as have a market value equal to twice the exercise price. 10. STOCK-BASED COMPENSATION PLANS The Company has implemented a Stock Option Plan, for directors, officers and employees. As of June 30, 2002, there were 14,500,000 common shares reserved for issuance to eligible participants. At June 30, 2002, 9,910,954 (December 31, 2001 - 9,829,334; December 31, 2000 - 6,352,335) options with exercise prices between $0.60 and $4.60 were outstanding and exercisable at various dates to June 19, 2012. The exercise price of each option equals the market price of the Company's common shares on the date of the grant. At the beginning of the year 2001, the Company had a share appreciation rights plan of which, the financial statement effects of this plan were determined not to be significant to the financial statements due to the amount vested. During the year 2001, this plan was cancelled and replaced by a fixed option plan with a variable component. F-15 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 10. STOCK-BASED COMPENSATION PLANS (CONTINUED) A certain number of outstanding fixed options included in the Company's Stock Option Plan have a variable compensation cost component to them. This variable cost component can vary in amount between a range based on the market value price of the Company's common shares and is capped at an amount of $4.4 million. The liability related to the variable component of these options amounts to $3.4 million, which is included in accounts payable as at June 30, 2002 (2001 - $3.9 million). The following tables summarize the information about the share options as at:
YEARS ENDED DECEMBER 31, SIX MONTHS ENDED ------------------------------------------------------- JUNE 30, 2002 2001 2000 ------------------------ ------------------------- -------------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE FIXED OPTIONS SHARES PRICE SHARES PRICE SHARES PRICE ------------- ------ ----- ------ ----- ------ ----- Outstanding at beginning of period 9,829,334 $2.03 6,352,335 $1.08 6,081,334 $1.00 Granted 919,070 $4.13 3,866,250 $3.57 500,000 $2.30 Exercised (358,099) $2.33 (314,584) $1.41 (56,667) $1.34 Cancelled (479,351) $3.83 (74,667) $3.63 (172,332) $1.45 ------------- ------------- ------------- Outstanding at end of period 9,910,954 $2.13 9,829,334 $2.03 6,352,335 $1.08 ============= ============= ============= Options exercisable at period end 7,505,879 $1.59 7,009,889 $1.42 5,719,001 $1.00 ============= ============= =============
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ----------------------------------------- --------------------------- NUMBER WEIGHTED NUMBER OUTSTANDING AVERAGE WEIGHTED EXERCISABLE WEIGHTED AT REMAINING AVERAGE AT AVERAGE JUNE 30, CONTRACTUAL EXERCISE JUNE 30, EXERCISE RANGE OF EXERCISE PRICES 2002 LIFE PRICE 2002 PRICE ------------------------ ------------- ---- ----- ------------- ----- $0.60 - $1.25 4,350,000 4.4 $ 0.76 4,350,000 $ 0.76 $1.45 - $2.30 1,526,667 7.2 $ 1.90 1,393,334 $ 1.86 $2.98 - $3.50 1,583,804 7.4 $ 3.03 1,068,644 $ 3.02 $3.80 - $4.60 2,450,483 9.0 $ 4.11 693,901 $ 4.05 ------------- ------------- 9,910,954 $ 2.13 7,505,879 $ 1.59 ============= =============
F-16 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 10. STOCK-BASED COMPENSATION PLANS (CONTINUED)
OPTIONS OUTSTANDING OPTIONS EXERCISABLE ------------------------------------------ ----------------------------- NUMBER WEIGHTED NUMBER OUTSTANDING AVERAGE WEIGHTED EXERCISABLE WEIGHTED AT REMAINING AVERAGE AT AVERAGE DECEMBER 31, CONTRACTUAL EXERCISE DECEMBER 31, EXERCISE RANGE OF EXERCISE PRICES 2001 LIFE PRICE 2001 PRICE ------------------------ ------------- ---- ----- ------------- ----- $0.60 - $1.25 4,380,000 5.17 $ 0.77 4,380,000 $ 0.77 $1.45 - $2.30 1,653,334 7.67 $ 1.87 1,436,667 $ 1.83 $2.98 - $3.50 1,922,900 9.75 $ 3.04 826,899 $ 3.02 $3.80 - $4.30 1,873,100 9.67 $ 4.10 366,323 $ 3.94 ------------- ------------- 9,829,334 $ 2.03 7,009,889 $ 1.42 ============= =============
CICA Handbook section 3870 "Stock-based Compensation", establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. The Company has elected to follow the intrinsic value method of accounting for stock-based compensation arrangements. Since all options were granted with an exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income at the time of the option grants. Had compensation cost for the Company's stock options been determined based on the fair market value at the grant dates of the awards consistent with methodology prescribed by Handbook section 3870, the Company's net income and net income per share would have been the pro forma amounts for the periods as indicated below:
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ------------------------- ---------------------------------------- 2002 2001 2001 2000 1999 ---- ---- ---- ---- ---- Net earnings: As reported $ 14,498 $ 47,495 $ 55,636 $ 40,059 $ 17,088 Pro forma $ 13,391 $ 47,230 $ 53,446 $ 39,407 $ 16,585 Net earnings per common share - basic: As reported $ 0.13 $ 0.44 $ 0.51 $ 0.37 $ 0.18 Pro forma $ 0.12 $ 0.44 $ 0.49 $ 0.37 $ 0.17 Net earnings per common share - diluted: As reported $ 0.12 $ 0.42 $ 0.48 $ 0.36 $ 0.17 Pro forma $ 0.11 $ 0.42 $ 0.47 $ 0.36 $ 0.17
F-17 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 10. STOCK-BASED COMPENSATION PLANS (CONTINUED) The weighted average fair market value of options granted in the six months ended June 30, 2002 and 2001 and for the years ended December 31, 2001, 2000 and 1999 are $3.24, $2.90, $2.52, $1.61 and $1.20 per option, respectively. The fair value of each option granted was estimated on the date of grant using the Modified Black-Scholes option-pricing model with the following assumptions:
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ------------------------- ---------------------------------------- 2002 2001 2001 2000 1999 ---- ---- ---- ---- ---- Risk-free interest rate 5.70% 5.39% 5.40% 5.54% 5.19% Estimated hold period prior to exercise (years) 10 10 10 10 10 Volatility in the price of the Company's common shares 67.26% 51.10% 53.75% 52.75% 46.92%
Handbook section 3870, also requires recognition of the compensation cost with respect to changes in intrinsic value for the variable component of fixed options outstanding during the period. During the six month period ended June 30, 2002, the Company recorded a compensation cost recovery of $412 thousand related to the outstanding variable component of these options (2001 - $280 thousand). 11. PER SHARE AMOUNTS In the calculation of diluted per share amounts, options under the stock option plan are assumed to have been converted or exercised on the later of the beginning of the year and the date granted. The treasury stock method is used to determine the dilutive effect of stock options. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market rate.
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ---------------------------- ------------------------------------------- 2002 2001 2001 2000 1999 ---- ---- ---- ---- ---- Weighted average shares outstanding (thousands) Basic 113,306 107,267 109,881 106,904 97,409 ======= ======= ======= ======= ======= Diluted 118,239 112,405 114,844 110,645 100,800 ======= ======= ======= ======= =======
F-18 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 12. INCOME TAXES a) PROVISION FOR INCOME TAXES
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ---------------------- ------------------------------------ 2002 2001 2001 2000 1999 ---- ---- ---- ---- ---- Earnings before taxes $ 24,731 $ 65,267 $ 79,214 $ 76,656 $ 29,069 Expected tax expense at combined federal and provincial rate of 42.1% 42.6% 42.6% 44.6% 44.6% $ 10,417 $ 27,804 $ 33,745 $ 34,204 $ 12,965 Increase (decrease) resulting from: Non-deductible crown charges 7,274 12,313 18,570 16,915 7,831 Non-deductible depletion -- -- -- -- 1,035 Alberta royalty tax credits (104) (106) (213) (291) (602) Resource allowance (5,439) (12,249) (22,984) (17,486) (7,207) Statutory rate change (2,135) (7,400) (7,400) -- -- Other (719) (3,138) 530 2,365 (2,240) -------- -------- -------- -------- -------- Provision for future income taxes $ 9,294 $ 17,224 $ 22,248 $ 35,707 $ 11,782 ======== ======== ======== ======== ========
b) FUTURE INCOME TAXES Future income taxes consist of the following temporary differences:
DECEMBER 31, JUNE 30, ---------------------------- 2002 2001 2000 ---- ---- ---- Property and equipment $ 170,798 $ 157,792 $ 136,351 Timing of partnership items 28,742 31,088 -- Resource allowance rate reduction (6,199) (5,315) (4,058) Non-capital losses (3,029) (2,162) -- Share issue costs and other (856) (1,542) (1,385) Future site restoration (813) (669) (606) ------------- ------------ ------------ Future income taxes $ 188,643 $ 179,192 $ 130,302 ============ ============ ============
F-19 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 13. FINANCIAL INSTRUMENTS The Company is exposed to fluctuations in commodity prices, interest rates and Canada/U.S. exchange rates. The Company, when appropriate, utilizes financial instruments to manage its exposure to these risks. a) COMMODITY PRICE RISK MANAGEMENT The Company enters into hedge transactions on crude oil and natural gas. The agreements entered into are forward transactions providing the Company with a range of fixed prices on the commodities sold. Oil and gas revenues for the period ended June 30, 2002 include gains of $288 thousand (2001 - $3.7 million gain; 2000 - $7.7 million loss; 1999 - $1.1 million loss) on these transactions. The following table outlines the financial agreements in place at June 30, 2002:
DAILY NOTIONAL UNRECOGNIZED TERM VOLUME PRICES RECEIVED (GAIN)/LOSS ---- ------ --------------- ----------- Natural Gas Collar Apr 02 - Oct 02 15,000 GJ $3.83/GJ - $5.45/GJ $ (818) Fixed price contract May 02 - Oct 02 5,000 GJ $4.50/GJ $ (683) Collar Nov 02 - Mar 03 5,000 GJ $4.50/GJ - $7.85/GJ $ -- Crude Oil Collar May 02 - Dec 02 1,500 bbls US$23.83/bbl - US$28.00/bbl $ -- Fixed price contract May 02 - Dec 02 500 bbls US$24.40/bbl $ 111
The following table outlines the financial agreements that were entered into by the Company, subsequent to June 30, 2002, and are currently outstanding:
DAILY NOTIONAL TERM VOLUME PRICES RECEIVED ---- ------ --------------- Natural Gas Collar Nov 02 - Mar 03 20,000 GJ $4.00/GJ - $6.55/GJ Crude Oil Collar Jan 03 - Dec 03 500 bbls US$23.50/bbl - US$27.00/bbl Fixed price contract Jan 03 - Dec 03 500 bbls US$25.00/bbl
b) FOREIGN CURRENCY EXCHANGE RISK MANAGEMENT The Company is exposed to fluctuations in the exchange rate between the Canadian dollar and the U.S. dollar. Crude oil, and to a large extent, natural gas prices, are based upon reference prices denominated in U.S. dollars, while the majority of the Company's expenses are denominated in Canadian dollars. When appropriate, the Company enters into agreements to fix the exchange rate of Canadian dollars to U.S. dollars in order to manage the risk of revenue losses if the Canadian dollar increases in value compared to the U.S. dollar. F-20 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 13. FINANCIAL INSTRUMENTS (CONTINUED) c) INTEREST RATE RISK MANAGEMENT The majority of the Company's long-term debt has a fixed interest rate and the Company periodically uses interest rate swaps to manage its debt servicing costs. The Company currently has an outstanding interest rate swap on a total of US$165 million of long-term debt. This swap converts fixed rate interest into floating rate interest (refer to Note 6(a)). The Company is exposed to changes in interest rates as a result of the senior credit facilities bearing interest of the Company's lenders' prime rate or at the Banker's Acceptance rate, or LIBOR plus applicable margins. At June 30, 2002, there was no amounts outstanding on the senior credit facility, thus for each one percentage change in interest rates on this floating rate debt had nil effect on net earnings. d) FAIR VALUE OF FINANCIAL ASSETS AND LIABILITIES The fair values of the Company's financial assets and liabilities that are included in the Company's Consolidated Balance Sheet as at June 30, 2002 approximate their carrying value. The fair value of the senior term notes does not significantly differ from the carrying amount since the estimated interest rates that would be available to the Company at June 30, 2002 approximate the actual interest rate of the senior term notes. e) CREDIT RISK MANAGEMENT Accounts receivable include amounts receivable for oil and gas sales which are generally made to large credit worthy purchasers, and amounts receivable from joint venture partners which are recoverable from production. Accordingly, the Company views credit risks on these amounts as low. The Company is exposed to losses in the event of non-performance by counter-parties to these financial instruments. The Company deals with major institutions and believes these risks are minimal. 14. CASH FLOW Changes in non-cash working capital items increased (decreased) cash and cash equivalents as follows:
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ---------------------------- ------------------------------------------- 2002 2001 2001 2000 1999 ---- ---- ---- ---- ---- Accounts receivable and other $ 3,065 $ 10,459 $ (413) $ (29,568) $ (26,427) Accounts payable (22,131) (6,462) 5,459 15,915 10,398 ------------ ------------- ------------ ------------ ------------ $ (19,066) $ 3,997 $ 5,046 $ (13,653) $ (16,029) ============ ============= ============ ============ ============ Operating activities $ 9,097 $ 3,941 $ (7,266) $ (13,346) $ (11,201) Investing activities (28,163) 56 12,312 (307) (4,828) ------------ ------------- ------------ ------------ ------------ $ (19,066) $ 3,997 $ 5,046 $ (13,653) $ (16,029) ============ ============= ============ ============ ============
F-21 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 14. CASH FLOW (CONTINUED) Amounts paid during the year relating to interest expense and capital taxes are as follows:
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, ---------------------------- ------------------------------------------- 2002 2001 2001 2000 1999 ---- ---- ---- ---- ---- Interest paid $ 2,869 $ 7,053 $ 13,054 $ 13,639 $ 6,576 Capital taxes paid $ 1,133 $ -- $ 793 $ 470 $ 314
15. COMMITMENTS AND CONTINGENT LIABILITIES a) The Company has committed to certain payments under operating leases over the next five years, as follows:
2002 2003 2004 2005 2006 ---- ---- ---- ---- ---- Equipment $ 1,740 $ 1,131 $ 203 $ -- $ -- Office rental 1,210 1,444 1,452 481 -- ----------- ----------- ----------- ----------- ----------- $ 2,950 $ 2,575 $ 1,655 $ 481 $ -- =========== =========== =========== =========== ===========
b) Legal proceedings The Company is involved in various legal claims associated with normal operations. These claims, although unresolved at the current time, are minor in nature and are not expected to have a material impact on the financial position or results of operations of the Company. 16. SUBSEQUENT EVENTS a) On May 8, 2002, the Company completed an offering of US$165 million, 9.90% senior notes due 2009. The senior notes are unsecured and were issued at a price per note of 98.273%. The net proceeds from the offering are approximately US$156.3 million and the Company used the net proceeds to repay its entire existing bank indebtedness and for general corporate purposes. b) As a result of the completion of the above mentioned senior notes offering, the Company's senior credit facilities as described in Note 6(b) have been adjusted to $168 million, comprised of a $158 million extendible revolving credit facility and a $10 million working capital facility. F-22 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING RECONCILIATION OF CONSOLIDATED FINANCIAL STATEMENTS TO UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES The Company's consolidated interim financial information has been prepared using the same accounting principles, practices and methods as those that were used for the Company's fiscal years. Accordingly, the accounting principles, practices and methods used in the preparation of the consolidated interim financial information vary from U.S. principles, practices and methods as described below. These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in Canada ("Canadian GAAP") which, in most respects, conforms to accounting principles generally accepted in the United States of America ("U.S. GAAP"). The significant differences in those principles, as they apply to the Company's statements of earnings, balance sheets and statements of cash flow, are as follows: a) Under U.S. GAAP, the carrying value of petroleum and natural gas properties and related facilities, net of future or deferred income taxes, is limited to the present value of after tax future net revenue from proven reserves, discounted at 10 percent, (based on prices and costs at the balance sheet date) plus the lower of cost and fair value of unproven properties. Under Canadian GAAP, the "ceiling test" is calculated without application of a discount factor to future net revenues, but estimated future general and administrative and financing costs are deducted from future net revenue. Prior to January 1, 2001, Canadian GAAP required the test to be performed annually, whereas U.S. GAAP required the ceiling test to be performed at the end of each quarter. Subsequent to January 1, 2001, Canadian GAAP requires the ceiling test to be performed at the end of each quarter. The Company has completed a ceiling test calculation at June 30, 2002 and December 31, 2001, 2000 and 1999 with no write-down required under either Canadian or U.S. GAAP. At December 31, 1998 the application of the full cost ceiling test under U.S. GAAP would have resulted in a write-down of capitalized costs of $13.8 million after income tax, utilizing commodity prices at December 31, 1998 of $15.33/bbl for crude oil and $2.50/mcf for natural gas. As commodity prices were uncharacteristically lower than normal at December 31, 1998 and considering a subsequent strengthening of prices in the first quarter of 1999, U.S. GAAP allows the Company to choose a different measurement date for purposes of calculating the full cost ceiling test. Accordingly, the application of the ceiling test at March 31, 1999 did not result in a write-down indicating that the capitalized costs were not in fact impaired at year end. The application of the full cost ceiling test under U.S. GAAP for years prior to the year ended December 31, 1998 did not result in a write-down of capitalized costs. b) Under U.S. GAAP, the provision for future site restoration costs is recorded as a reduction of property and equipment in the amount of $1.9 million at June 30, 2002 (December 31, 2001 - $1.6 million; 2000 - $1.4 million). F-23 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) c) Statement of Financial Accounting Standards ("SFAS") 123, "Accounting for Stock-based Compensation", establishes financial accounting and reporting standards for stock-based employee compensation plans as well as transactions in which an entity issues its equity instruments to acquire goods or services from non-employees. As permitted by SFAS 123, the Company has elected to follow the intrinsic value method of accounting for stock-based compensation arrangements, as provided for in Accounting Principles Board Opinion 25 ("APB 25"). Since all options were granted with an exercise price equal to the market price at the date of the grant, no compensation cost has been charged to income at the time of the option grants. As discussed in Note 10, the Company retroactively adopted effective January 1, 2001, the standards of accounting released by the CICA for stock based compensation. These standards are consistent with SFAS 123. APB 25, as interpreted by the Financial Accounting Standards Board ("FASB") interpretation 44, also requires recognition of compensation cost with respect to changes in intrinsic value for variable employee stock compensation plans. As a result of the modifications to the terms of employee stock options, the modified options are subject to variable plan accounting, which result in a compensation cost of $4.5 million and $1.5 million for the years ended December 31, 2000 and 1999 for U.S. GAAP purposes. d) Prior to January 1, 2000, the Company recorded the renouncement of tax deductions resulting from the issuance of flow-though shares by reducing property and equipment and share capital by the estimated cost of the tax deductions renounced. U.S. GAAP requires that flow-through shares be recorded at their fair value without any adjustment for the renouncement of the tax deductions and any temporary difference resulting from the renouncement must be recognized in the determination of tax expense in the year incurred. U.S. GAAP also requires the estimated cost of the tax deductions renounced be recorded as a future income tax liability rather than a reduction of petroleum and natural gas properties. Subsequent to January 1, 2000, the Company accounted for the estimated cost of the tax deduction renounced as a future tax liability and hence was consistent with U.S. GAAP. See Note 3(c) for the effect of this accounting policy change on property and equipment and future income taxes in 2000. The effect of increasing property and equipment to stated value in 1999 was to increase depletion by $1.3 million and to reduce future income taxes by $0.6 million. The impact of recording flow-through shares at their fair value for the six months ended June 30, 2002, was to increase the future income tax provision by nil (six months ended June 30, 2001 - nil; year ended December 31, 2001 - $8.7 million; 2000 - $4.7 million; 1999 - $4.9 million) and to increase capital stock by a corresponding amount. In addition, as at January 1, 1999, retained earnings was decreased by $5.5 million and capital stock increased by $5.5 million to retroactively adjust for prior year flow-through share issuances. Prior to January 1, 2000, the charge for depletion and depreciation will be lower for Canadian GAAP as compared to U.S. GAAP because of the reduction of petroleum and natural gas properties for the cost of the tax deductions renounced. F-24 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) e) Prior to year 2000, the Company followed the deferral method of accounting for income taxes. Under this method, there was a matching of the income tax expense with the reported pre-tax accounting income. In the United States, Statement of Financial Accounting Standards No. 109 requires the use of the asset and liability method. Under this method, a tax liability or asset is recognized for the differences between reported values and the tax basis of the assets and liabilities. The Company adopted the liability method of accounting for income taxes in 2000 retroactively, without restating the financial statements of prior periods. f) Statement of Financial Accounting Standards No. 130 "Comprehensive Income" requires the reporting of comprehensive income in addition to net earnings. Comprehensive income includes net income plus other comprehensive income. Management believes that it has no other comprehensive income other than as described under note 17(g). g) SFAS No. 133, "Accounting for Derivative instruments and Hedging Activities", as amended by SFAS 137 and SFAS 138, was issued in June 1998 by the FASB. SFAS 133 establishes new accounting and reporting standards for derivative instruments and for hedging activities. This statement requires the Company to measure all derivatives at fair value and to recognize them in the balance sheet as an asset or liability, depending on the Company's rights or obligations under the applicable derivative contract. Changes in the fair value of derivatives will be recorded each quarter in net income or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and, if it is, depending on the type of hedge transaction. The ineffective portion of all hedges will be recognized in net income. If a derivative does not qualify as a hedging relationship, the derivative is recorded at fair value and changes in its fair value will be reported in net income. Under the current accounting policy for derivatives, only derivatives used in sales and trading activities are recorded on the balance sheet at fair value. The effective date of SFAS 133 for the Company is at January 1, 2001. DERIVATIVES The Company used forward contracts and options on forward contracts to manage the risk of fluctuations in the market price of natural gas and crude oil, and the change in interest rates. During the six months ended June 30, 2002, the Company had 6 forward contracts. As at June 30, 2002, the natural gas and crude oil futures contracts determined to be derivatives under SFAS 133 are accounted for as cash flow hedges and expire on various dates through December 2003. These contracts are recorded at fair value on the Balance Sheet in the amount of $2.1 million as of June 30, 2002 (2001 - $187 thousand). The offset of the change in fair value is recorded in comprehensive income, net of tax, and subsequently recognized as a component of Operating expense on the Statement of Earnings and Retained Earnings when the underlying product being hedged is purchased. The effective portion of these commodity contracts is $1.2 million, which is recorded in comprehensive income as of June 30, 2002 (2001 - $123 thousand), and the ineffective portion of these commodity contracts was immaterial for the periods ended June 30, 2002 and December 31, 2001. F-25 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) CONSOLIDATED STATEMENTS OF OPERATIONS The application of U.S. GAAP would have the following effect on net income:
SIX MONTHS ENDED JUNE 30, YEARS ENDED DECEMBER 31, -------------------- --------------------------------- 2002 2001 2001 2000 1999 ---- ---- ---- ---- ---- Net income for the period, as reported $ 14,498 $ 47,495 $ 55,636 $ 40,059 $ 17,088 Adjustments: Depletion (d) -- -- -- -- (1,262) Depletion (e) -- -- -- -- (5,946) Related income taxes -- -- -- -- 3,215 Compensation costs (c) -- -- -- (4,484) (1,466) Related income taxes -- -- -- 2,000 654 Accounting for income taxes (d) -- -- (8,715) (4,694) (4,938) -------- -------- -------- -------- -------- Net income for the year - U.S. GAAP $ 14,498 $ 47,495 $ 46,921 $ 32,881 $ 7,345 ======== ======== ======== ======== ======== Net income per common share - U.S. GAAP Basic $ 0.13 $ 0.44 $ 0.43 $ 0.31 $ 0.08 Diluted $ 0.12 $ 0.42 $ 0.41 $ 0.30 $ 0.07 Statement of comprehensive income (f) Net income for the year - U.S. GAAP $ 14,498 $ 47,495 $ 46,921 $ 32,881 $ 7,345 Accounting for hedging (g) 1,230 -- 123 -- -- -------- -------- -------- -------- -------- Comprehensive income $ 15,728 $ 47,495 $ 47,044 $ 32,881 $ 7,345 ======== ======== ======== ======== ======== Depletion and depreciation expense - U.S. GAAP $ 26,427 $ 23,789 $ 50,450 $ 41,767 $ 27,368 ======== ======== ======== ======== ======== Depletion and depreciation expense - U.S. GAAP per BOE produced $ 7.61 $ 7.73 $ 7.69 $ 7.04 $ 5.94 ======== ======== ======== ======== ========
F-26 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) CONSOLIDATED BALANCE SHEETS The application of U.S. GAAP would have the following effect on the balance sheets: JUNE 30, 2002 ----------------------------------- INCREASE AS REPORTED (DECREASE) U.S. GAAP ----------- ---------- --------- Assets Property and equipment (b) $623,572 $ (1,930) $621,642 Accounting for hedging (g) -- 2,144 2,144 Liabilities Site restoration costs (b) $ 1,930 $ (1,930) $ -- Future income (g) 188,643 914 189,557 Shareholders' equity Capital stock (d) $118,293 $ 23,843 $142,136 Retained earnings (see schedule below) 114,877 (22,613) 92,264 DECEMBER 31, 2001 ----------------------------------- INCREASE AS REPORTED (DECREASE) U.S. GAAP ----------- ---------- --------- Assets Property and equipment (b) $606,920 $ (1,569) $605,351 Accounting for hedging (g) -- 187 187 Liabilities Site restoration costs (b) $ 1,569 $ (1,569) $ -- Future income taxes (g) 179,192 64 179,256 Shareholders' equity Capital stock (d) $116,572 $ 23,843 $140,415 Retained earnings (see schedule below) 101,288 (23,720) 77,568 F-27 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) DECEMBER 31, 2000 ----------------------------------- INCREASE AS REPORTED (DECREASE) U.S. GAAP ----------- ---------- --------- U.S. GAAP Assets Property and equipment (b) $442,897 $ (1,359) $441,538 Liabilities Site restoration costs (b) $ 1,359 $ (1,359) $ -- Future income taxes (e) 130,302 (2,687) 127,615 Other (c) -- 6,024 6,024 Shareholders' equity Capital stock (d) $ 94,472 $ 15,128 $109,600 Retained earnings (see schedule below) 63,324 (18,465) 44,859 DECEMBER 31, JUNE 30, ----------------------- 2002 2001 2000 ---- ---- ---- Retained earnings under Canadian GAAP $ 114,877 $ 101,288 $ 63,324 Flow-through share differences (d) (23,843) (23,843) (15,128) Stock option expense adjustments -- -- (6,024) Adjustment to future income taxes (c) -- -- 2,687 Commodity derivatives (g) 1,230 123 -- --------- --------- --------- Retained earnings under U.S. GAAP $ 92,624 $ 77,568 $ 44,859 ========= ========= ========= CONSOLIDATED STATEMENTS OF CASH FLOW The application of U.S. GAAP would not change the amounts as reported under Canadian GAAP for cash flows provided by (used in) operating, investing or financing activities, except for the following: (i) Unspent flow-through share proceeds which have been received at December 31, 2001. During 2001, the Company received $41.8 million in proceeds from the issuance of flow-through shares of which $25.6 million remained unspent as at December 31, 2001 (December 31, 2000 - $12.5 million). Accordingly, under U.S. GAAP, these proceeds would be disclosed separately on the balance sheet of Compton as restricted cash and would not be treated as cash or cash equivalents for statement of cash flow reporting purposes. The result of this difference would be to disclose an increase in restricted cash as an investing activity and to reduce cash, end of year by $25.6 million at December 31, 2001 (December 31, 2000 - $12.5 million); F-28 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) (ii) The consolidated statements of cash flow includes, under investing activities, items not affecting cash, related to the non-cash elements of corporate acquisitions and, to other line items, principally property and equipment additions. This disclosure is provided in order to disclose the aggregate costs related to such activities and to then deduct the related non-cash amount to arrive at the cash amounts. This presentation is not permitted under U.S. GAAP; and (iii) The consolidated statements of cash flow includes, under investing activities, site restoration costs. Under U.S. GAAP these costs would be presented under operating activities. (iv) The consolidated statements of cash flow, for the year ended December 31, 1999, disclosed a negative ending cash balance of $15.1 million. Under U.S. GAAP, this negative ending cash balance (or bank overdrafts) would be reflected as a financing activity in the consolidated statements of cash flow. ADDITIONAL U.S. GAAP DISCLOSURE
DECEMBER 31, JUNE 30, -------------------------------- 2002 2001 2000 ---- ---- ---- Accounts receivable includes the following: Revenue receivable $ 40,595 $ 37,101 $ 44,696 Joint interest receivable 24,603 26,132 26,388 Other receivables 13,754 18,785 10,308 Allowance for doubtful accounts (17) (17) (17) ------------ ------------ ------------ $ 78,935 $ 82,001 $ 81,375 ============ ============ ============
DECEMBER 31, JUNE 30, -------------------------------- 2002 2001 2000 ---- ---- ---- Accounts payable and accrued liabilities includes the following: Trade payables $ 31,735 $ 52,393 $ 39,537 Royalties payable 6,960 3,202 5,593 Taxes payable 950 2,359 150 Other payables 3,128 6,949 6,159 ------------ ------------ ------------ $ 42,773 $ 64,903 $ 51,439 ============ ============ ============
F-29 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) The aggregate capitalized costs of oil and gas activities and costs incurred in oil and gas property acquisitions, development and exploration activities are as follows: Capitalized costs DECEMBER 31, JUNE 30, ----------------------- 2002 2001 2000 ---- ---- ---- Proved properties $ 606,762 $ 566,074 $ 414,493 Unproven properties: Acquisition 112,068 110,764 72,309 Exploration 50,882 50,205 26,446 Accumulated depletion and depreciation (146,140) (120,123) (70,351) --------- --------- --------- $ 623,572 $ 606,920 $ 442,897 ========= ========= ========= Costs incurred on unproved properties INCLUDES COSTS INCURRED IN JUNE 30, ------------------------------------------------------ 2002 2002 2001 2000 1999 PRIOR YEARS -------- -------- -------- -------- -------- ----------- Acquisition $112,068 $ 1,304 $ 38,455 $ 26,006 $ 17,535 $ 28,768 Exploration 50,882 677 23,759 17,143 9,303 -- -------- -------- -------- -------- -------- -------- $162,950 $ 1,981 $ 62,214 $ 43,149 $ 26,838 $ 28,768 ======== ======== ======== ======== ======== ======== Costs incurred 2001 2000 1999 ---- ---- ---- Acquisition costs (net of disposition) Proven properties $ 30,716 $ 241 $ 24,309 Unproven properties 38,455 26,006 17,535 Development costs Development of proven undeveloped reserves 16,088 19,573 7,727 Other 27,229 48,582 16,126 Exploration costs 75,417 23,992 40,001 -------- -------- -------- Total costs incurred $187,905 $118,394 $105,698 ======== ======== ======== F-30 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) Costs are transferred into the depletion base on an ongoing basis as the undeveloped properties are evaluated and proved reserves are established or impairment determined. Pending determination of proved reserves attributable to the above costs, the Company cannot assess the future impact on the amortization rate. DECEMBER 31, JUNE 30, ----------------------- 2002 2001 2000 ---- ---- ---- Future income tax liabilities Property and equipment $ 199,540 $ 188,880 $ 133,664 Future income tax assets Other temporary differences (6,199) (5,315) (4,058) Abandonment costs (813) (669) (606) Loss carry forward (3,029) (2,162) -- Other 58 (1,478) (1,385) --------- --------- --------- Future income taxes $ 189,557 $ 179,256 $ 127,615 ========= ========= ========= RECENT ACCOUNTING PRONOUNCEMENTS On July 20, 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 141, BUSINESS COMBINATIONS, and SFAS 142, GOODWILL AND INTANGIBLE ASSETS. SFAS 141 is effective for all business combinations completed after June 30, 2001. SFAS 142 is effective for fiscal years beginning after December 15, 2001; however, certain provisions of this Statement apply to goodwill and other intangible assets acquired between July 1, 2001 and the effective date of SFAS 142. Major provisions of these Statements and their effective dates for the Company are as follows: o All business combinations initiated after June 30, 2001 must use the purchase method of accounting. The pooling of interest method of accounting is prohibited except for transactions initiated before July 1, 2001. o Intangible assets acquired in a business combination must be recorded separately from goodwill if they arise from contractual or other legal rights or are separable from the acquired entity and can be sold, transferred, licensed, rented or exchanged, either individually or as part of a related contract, asset or liability. o Goodwill, as well as intangible assets with indefinite lives, acquired after June 30, 2001, will not be amortized. Effective January 1, 2002, all previously recognized goodwill and intangible assets with indefinite lives will no longer be subject to amortization. o Effective January 1, 2002, goodwill and intangible assets with indefinite lives will be tested for impairment annually and whenever there is an impairment indicator. F-31 ================================================================================ COMPTON PETROLEUM CORPORATION NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (Tabular amounts in thousands of Canadian dollars, unless otherwise stated) (Information as at June 30, 2002 and for the six month period ended June 30, 2002 and 2001 is unaudited) -------------------------------------------------------------------------------- 17. UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING (CONTINUED) RECENT ACCOUNTING PRONOUNCEMENTS (continued) o All acquired goodwill must be assigned to reporting units for purposes of impairment testing and segment reporting. Management's assessment is that these Statements do not have a material impact on the Company's financial position or results of operations. In July 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. This Statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This Statement applies to all entities. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and (or) the normal operation of a long-lived asset, except for certain obligations of lessees. This Statement is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company is evaluating the impact of the adoption of this standard and has not yet determined the effect of adoption on its financial position and results of operations. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets and supersedes FASB Statement No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets To Be Disposed Of. The provisions of the statement are effective for financial statements issued for fiscal years beginning after December 15, 2001. Management's assessment is that this Statement do not have a material impact on the Company's financial position or results of operations. In July 2002, the FASB issued Statement 146, ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES. SFAS 146 nullifies EITF 94-3, LIABILITY RECOGNITION FOR CERTAIN EMPLOYEE TERMINATION BENEFITS AND OTHER COSTS TO EXIT AN ACTIVITY (INCLUDING CERTAIN COSTS INCURRED IN A RESTRUCTURING.). SFAS 146 requires the recognition of a liability for costs associated with exit or disposal activities when a liability is incurred; that is, the costs meet the definition of a liability in accordance with Concepts Statement 6, ELEMENTS OF FINANCIAL STATEMENTS. The statement also provides guidance on the required disclosures of exit and disposal activities. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. F-32 18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) The net proved oil and natural gas reserve estimates as of December 31, 1999, 2000 and 2001 set forth below were prepared in accordance with guidelines established by the Securities and Exchange Commission and accordingly were based on existing economic and operating conditions. Oil and natural gas prices in effect as of the respective year ends were used without any escalation except in those instances where the sale is covered by contract, in which case the applicable contract prices is used. Operating costs, royalties and future development costs were based on current costs with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. Moreover, the present value should not be construed as the current market value of the Company's oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. All of the reserves are located in Canada. ESTIMATED QUANTITIES OF RESERVES
YEARS ENDED DECEMBER 31, ------------------------------------------------------------------------ 1999 2000 2001 ----------------------- ----------------------- ------------------- CRUDE OIL NATURAL CRUDE OIL NATURAL CRUDE OIL NATURAL & NGL's gas & NGL's gas & NGL's gas (MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF) ------- ------ ------- ------ ------- ------ Balance, beginning of year 7,272 155,659 10,682 181,759 9,423 223,761 Revisions of previous estimates 774 (14,832) (2,524) 1,715 313 (3,186) Extensions, discoveries and other additions 1,531 23,262 1,399 60,495 1,611 63,248 Acquisitions of minerals in place 2,429 38,586 1,809 8,761 301 7,412 Dispositions of minerals in place (20) (1,082) (180) (3,930) (45) (382) Production (1,304) (19,834) (1,763) (25,039) (1,826) (28,405) -------- -------- -------- -------- -------- -------- Balance, end of year 10,682 181,759 9,423 223,761 9,777 262,448 ======== ======== ======== ======== ======== ======== Proved developed reserve Balance, beginning of year 6,589 140,823 8,629 156,939 8,576 187,969 Balance, end of year 8,629 156,939 8,576 187,969 8,938 232,319
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN RELATING TO PROVED OIL AND NATURAL GAS RESERVES The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves ("Standardized Measure") does not purport to present the fair market value of the Company's oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, the probability of recoveries in excess of existing proved reserves and acreage prospects, and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revisions. Under the Standardized Measure, future cash inflows were estimated by applying year end prices, adjusted for contracts currently in place to deliver production to the estimated future production of year end proved reserves. Future cash inflows were reduced by estimated future production and development costs based on year end costs to determine pre-tax cash inflows. Future taxes were computed by applying the statutory tax rate to the excess of F-33 18. SUPPLEMENTAL RESERVE INFORMATION (UNAUDITED) (CONTINUED) pre-tax cash inflows over the Company's tax basis in the associated proved oil and natural gas properties. Tax credits and net operating loss carry forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
YEARS ENDED DECEMBER 31, ------------------------------------------ 1999 2000 2001 ------------------------------------------ (in thousands of Canadian dollars) Future cash inflows $ 928,813 $ 2,524,446 $ 1,270,787 Future production costs (283,296) (382,540) (431,127) Future development costs (29,478) (41,035) (41,943) ----------- ----------- ----------- Future net cash flows 616,039 2,100,871 797,717 Income taxes (221,237) (907,123) (264,960) ----------- ----------- ----------- Total undiscounted future net cash flows 394,802 1,193,748 532,757 10% annual discount for estimated timing of cash inflows (123,316) (483,879) (215,296) ----------- ----------- ----------- Standardized measure of discounted future net cash $ 271,486 $ 709,869 $ 317,461 =========== =========== ===========
(1) The Company estimates that it will incur $6.9 million in 2002, $14.9 million in 2003 and $ nil in 2004 to develop proved undeveloped reserves. The following table sets forth an analysis of changes in the Standardized Measure of Discounted Future Net Cash Flows from proved oil and natural gas reserves:
YEARS ENDED DECEMBER 31, ----------------------------------------- 1999 2000 2001 ----------------------------------------- (in thousands of Canadian dollars) Beginning of year $ 131,146 $ 271,486 $ 709,869 Sales of production, net of production costs (60,389) (137,110) (151,724) Net change in sales prices, net of production costs 125,292 783,990 (807,804) Extensions, discoveries and additions 58,558 116,197 127,656 Changes in estimated future development costs (31,182) (26,630) (48,528) Development costs incurred during the period which reduced future development costs 42,514 51,305 58,982 Revisions in quantity estimates (1,955) 88,175 (2,099) Accretion of discount 17,040 35,497 111,245 Purchase of reserves 86,467 87,440 17,976 Sales of reserves (1,510) (7,783) (1,517) Net change in income tax (67,119) (395,612) 389,962 Changes in production rates (timing) and other (27,376) (157,086) (86,557) --------- --------- --------- Standardized measure, end of year $ 271,486 $ 709,869 $ 317,461 ========= ========= =========
F-34 [GRAPHIC OMITTED] [LOGO - COMPTON PETROLEUM CORPORATION] COMPTON -------------------------------------- PETROLEUM CORPORATION EXCHANGE OFFER OF US$165,000,000 OF OUR 9.90% SENIOR NOTES DUE 2009 ------------------------------ PROSPECTUS [____], 2002 ------------------------------ No person has been authorized to give any information or to make any representation other than those contained in this prospectus, and, if given or made, any information or representations must not be relied upon as having been authorized. This prospectus does not constitute an offer to sell or the solicitation of an offer to buy any securities other than the securities to which it relates or an offer to sell or the solicitation of an offer to buy these securities in any circumstances in which this offer or solicitation is unlawful. Neither the delivery of this prospectus nor any sale made under this prospectus shall, under any circumstances, create any implication that there has been no change in the affairs of Compton Petroleum Corporation since the date of this prospectus or that the information contained in this prospectus is correct as of any time subsequent to its date. Dealer Prospectus Delivery Obligation: Until the 41st day after the date of this prospectus, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the broker-dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions. PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS (a) Compton Petroleum Corporation Hornet Energy Ltd. 867791 Alberta Ltd. 899776 Alberta Ltd. The BUSINESS CORPORATIONS ACT (Alberta) and the CANADA BUSINESS CORPORATIONS ACT provides that a corporation may, in certain circumstances, indemnify a director or officer of the corporation, a former director or officer of the corporation, a person who acts or acted at the corporation's request as a director or officer of a body corporate of which the corporation is or was a shareholder or creditor and the heirs and legal representatives of any such persons (collectively, "Indemnified Persons") against all costs, charges and expenses reasonably incurred by any such Indemnified Person in respect of any civil, criminal or administrative action or proceeding to which he is made a party by reason of being or having been a director or officer of the corporation or other body corporate, if (a) he acted honestly and in good faith with a view to the best interests of the corporation, and (b) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, he had reasonable grounds for believing that his conduct was lawful. The by-laws of the Registrant provide that it shall indemnify Indemnified Persons of the Registrant to the maximum extent permitted by the BUSINESS CORPORATIONS ACT (Alberta). Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors and officers and persons controlling the Registrant pursuant to the foregoing provisions, the Registrant has been advised that, in the opinion of the Commission, such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. The Registrant carries certain insurance coverage, in respect of potential claims against its directors and officers and in respect of losses of which the Registrant may be required or permitted by law to indemnify such directors and officers. (b) Compton Petroleum The PARTNERSHIP ACT (Alberta) provides that each partner in a partnership is liable jointly with the other partners for debts and obligations of the partnership incurred while they are a partner. Accordingly, as the partners to the Compton Petroleum partnership are incorporated under the BUSINESS CORPORATIONS ACT (Alberta) or the CANADA BUSINESS CORPORATION ACT, the indemnification of the directors or officers of each partnership will be as set forth above. ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (a) EXHIBITS EXHIBIT NUMBER DESCRIPTION ------ ----------- 3.1* Articles of Incorporation of Compton Petroleum Corporation. 3.2* Articles of Incorporation of Hornet Energy Ltd. 3.3* Articles of Incorporation of 867791 Alberta Ltd. 3.4** Articles of Incorporation of 899776 Alberta Ltd. 3.5* Declaration of Partnership of Compton Petroleum. 3.6* By-laws of Compton Petroleum Corporation. 3.7* By-laws of Hornet Energy Ltd. 3.8* By-laws of 867791 Alberta Ltd. 3.9* By-laws of 899776 Alberta Ltd. 3.10* Partnership Agreement of Compton Petroleum. 4.1* Indenture, dated as of May 8, 2002, among Compton Petroleum Corporation, Hornet Energy Ltd., 867791 Alberta Ltd., 899776 Alberta Ltd., Compton Petroleum and the Bank of Nova Scotia Trust Company of New York, as trustee. 4.2** Form of Note. 5.1* Opinion of Fraser Milner Casgrain LLP regarding the legality of the notes and subsidiary guarantees. 5.2* Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding the legality of the notes and subsidiary guarantees. 8.1* Opinion of Fraser Milner Casgrain LLP regarding Canadian tax matters. 8.2* Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding U.S. tax matters. 10.1* Registration Rights Agreement, dated as of May 8, 2002 among Compton Petroleum Corporation, Hornet Energy Ltd., 867791 Alberta Ltd., 899776 Alberta Ltd., Compton Petroleum, Lehman Brothers, BMO Nesbitt Burns, Scotia Capital and TD Securities. 10.2* Second Amended and Restated Extendible Credit Agreement, dated May 8, 2002, between Compton Petroleum Corporation and the Bank of Montreal, The Bank of Nova Scotia and the Toronto-Dominion Bank. 10.3** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Kim Davies. 10.4** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Norman G. Knecht. 10.5** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Ernest G. Sapieha. 10.6** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Murray J. Stodalka. 12.1** Statement regarding computation of ratios. 21.1* List of subsidiaries. 23.1* Consent of Fraser Milner Casgrain LLP. 23.2** Consent of Grant Thornton LLP. 23.3* Consent of Outtrim Szabo Associates Ltd. 23.4* Consent of Paul, Weiss, Rifkind, Wharton & Garrison. 24.1* Powers of Attorney (included on the signature page hereto). 25.2* Statement of Eligibility on Form T-1 of The Bank of Nova Scotia Trust Company of New York. 99.1* Form of Letter of Transmittal. 99.2* Form of Notice of Guaranteed Delivery. ------------------------ * Previously filed. ** Filed herewith. (b) FINANCIAL STATEMENT SCHEDULES All schedules for which provision is made in the applicable accounting regulations of the Commission are not required, are inapplicable or have been disclosed in the notes to other financial statements and therefore have been omitted. ITEM 22. UNDERTAKINGS Each of the Registrants hereby undertakes: (i) to respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means; and (ii) to arrange or provide for a facility in the U.S. for the purpose of responding to such requests. The undertaking in subparagraph (i) above includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request. Each of the Registrants hereby undertakes to supply by means of a post-effective amendment all information concerning a transaction and the company being acquired involved therein, that was not the subject of and included in the registration statement when it became effective. SIGNATURES Pursuant to the requirements of the Securities Act of 1933, Compton Petroleum Corporation has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Province of Alberta, Canada, on September 19, 2002. COMPTON PETROLEUM CORPORATION By: /s/ Norman G. Knecht --------------------------------------- Name: Norman G. Knecht Title: Vice-President, Finance and Chief Financial Officer Pursuant to the requirements of the Securities Act of 1933, Compton Petroleum has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Province of Alberta, Canada, on September 19, 2002. COMPTON PETROLEUM By its managing partner, Compton Petroleum Corporation: By: /s/ Norman G. Knecht --------------------------------------- Name: Norman G. Knecht Title: Vice-President, Finance and Chief Financial Officer Pursuant to the requirements of the Securities Act, this Amendment No. 1 to the Registration Statement has been signed by the following persons in the capacities indicated on September 19, 2002. SIGNATURE TITLE --------- ----- * Director ----------------------------- Mel F. Belich /s/ Norman G. Knecht Vice President Finance and Chief ----------------------------- Financial Officer Norman G. Knecht (Principal Financial and Accounting Officer) * Director ----------------------------- John W. Preston * Director, President and Chief ----------------------------- Executive Officer Ernest G. Sapieha (Principal Executive Officer) Director ----------------------------- Jeffrey T. Smith *By: /s/ Norman G. Knecht --------------------------------- Name: Norman G. Knecht Title: Attorney-in-Fact SIGNATURES Pursuant to the requirements of the Securities Act of 1933, Hornet Energy Ltd. has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Province of Alberta, Canada, on September 19, 2002. HORNET ENERGY LTD. By: /s/ Norman G. Knecht --------------------------------------- Name: Norman G. Knecht Title: Vice-President, Finance and Chief Financial Officer Pursuant to the requirements of the Securities Act, this Amendment No. 1 to the Registration Statement has been signed by the following persons in the capacities indicated on September 19, 2002. SIGNATURE TITLE --------- ----- * President and Chief Executive Officer ----------------------------- and Director Ernest G. Sapieha /s/ Norman G. Knecht Vice President, Finance and Chief ----------------------------- Financial Officer Norman G. Knecht * Director ----------------------------- John W. Preston *By: /s/ Norman G. Knecht --------------------------------- Name: Norman G. Knecht Title: Attorney-in-Fact SIGNATURES Pursuant to the requirements of the Securities Act of 1933, 867791 Alberta Ltd. has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Province of Alberta, Canada, on September 19, 2002. 867791 ALBERTA LTD. By: /s/ Norman G. Knecht --------------------------------------- Name: Norman G. Knecht Title: Secretary Pursuant to the requirements of the Securities Act, this Amendment No. 1 to the Registration Statement has been signed by the following persons in the capacities indicated on September 19, 2002. SIGNATURE TITLE --------- ----- * President and sole director ----------------------------- Ernest G. Sapieha /s/ Norman G. Knecht Secretary ----------------------------- Norman G. Knecht *By: /s/ Norman G. Knecht --------------------------------- Name: Norman G. Knecht Title: Attorney-in-Fact SIGNATURES Pursuant to the requirements of the Securities Act of 1933, 899776 Alberta Ltd. has duly caused this Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Calgary, Province of Alberta, Canada, on September 19, 2002. 899776 ALBERTA LTD. By: /s/ Norman G. Knecht --------------------------------------- Name: Norman G. Knecht Title: Vice-President, Finance Pursuant to the requirements of the Securities Act, this Amendment No. 1 to the Registration Statement has been signed by the following persons in the capacities indicated on September 19, 2002. SIGNATURE TITLE --------- ----- * President and Director ----------------------------- Ernest G. Sapieha /s/ Norman G. Knecht Vice-President, Finance and Director ----------------------------- Norman G. Knecht *By: /s/ Norman G. Knecht --------------------------------- Name: Norman G. Knecht Title: Attorney-in-Fact AUTHORIZED REPRESENTATIVE Pursuant to the requirements of Section 6(a) of the Securities Act of 1933, the Authorized Representative has signed this Amendment No. 1 to the Registration Statement, solely in the capacity of the duly authorized representative of Compton Petroleum Corporation, Hornet Energy Ltd., 867791 Alberta Ltd., 899776 Alberta Ltd. and Compton Petroleum in the United States, on September 19, 2002. COMPTON PETROLEUM (USA) CORPORATION (Authorized U.S. Representative) By: /s/ Norman G. Knecht --------------------------------------- Name: Norman G. Knecht Title: Authorized Signatory EXHIBIT NUMBER DESCRIPTION ------ ----------- 3.1* Articles of Incorporation of Compton Petroleum Corporation. 3.2* Articles of Incorporation of Hornet Energy Ltd. 3.3* Articles of Incorporation of 867791 Alberta Ltd. 3.4** Articles of Incorporation of 899776 Alberta Ltd. 3.5* Declaration of Partnership of Compton Petroleum. 3.6* By-laws of Compton Petroleum Corporation. 3.7* By-laws of Hornet Energy Ltd. 3.8* By-laws of 867791 Alberta Ltd. 3.9* By-laws of 899776 Alberta Ltd. 3.10* Partnership Agreement of Compton Petroleum. 4.1* Indenture, dated as of May 8, 2002, among Compton Petroleum Corporation, Hornet Energy Ltd., 867791 Alberta Ltd., 899776 Alberta Ltd., Compton Petroleum and the Bank of Nova Scotia Trust Company of New York, as trustee. 4.2** Form of Note. 5.1* Opinion of Fraser Milner Casgrain LLP regarding the legality of the notes and subsidiary guarantees. 5.2* Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding the legality of the notes and subsidiary guarantees. 8.1* Opinion of Fraser Milner Casgrain LLP regarding Canadian tax matters. 8.2* Opinion of Paul, Weiss, Rifkind, Wharton & Garrison regarding U.S. tax matters. 10.1* Registration Rights Agreement, dated as of May 8, 2002 among Compton Petroleum Corporation, Hornet Energy Ltd., 867791 Alberta Ltd., 899776 Alberta Ltd., Compton Petroleum, Lehman Brothers, BMO Nesbitt Burns, Scotia Capital and TD Securities. 10.2* Second Amended and Restated Extendible Credit Agreement, dated May 8, 2002, between Compton Petroleum Corporation and the Bank of Montreal, The Bank of Nova Scotia and the Toronto-Dominion Bank. 10.3** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Kim Davies. 10.4** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Norman G. Knecht. 10.5** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Ernest G. Sapieha. 10.6** Employment Agreement, dated April 22, 1998, between Compton Petroleum Corporation and Murray J. Stodalka. 12.1** Statement regarding computation of ratios. 21.1* List of subsidiaries. 23.1* Consent of Fraser Milner Casgrain LLP. 23.2** Consent of Grant Thornton LLP. 23.3* Consent of Outtrim Szabo Associates Ltd. 23.4* Consent of Paul, Weiss, Rifkind, Wharton & Garrison. 24.1* Powers of Attorney (included on the signature page hereto). 25.2* Statement of Eligibility on Form T-1 of The Bank of Nova Scotia Trust Company of New York. 99.1* Form of Letter of Transmittal. 99.2* Form of Notice of Guaranteed Delivery. ------------------------ * Previously filed. ** Filed herewith.