Compton Petroleum F-10/A Registration of securities (Canada) (amended)

As filed with the Securities and Exchange Commission on December 23, 2005

Registration No. 333-130144

U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 1

TO

FORM F-10

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Compton Petroleum Finance Corporation

(Exact name of Registrant as specified in its charter)

Alberta, Canada	1311	Not Applicable
(Province or other jurisdiction of	(Primary Standard Industrial	(I.R.S. Employer Identification
incorporation or organization)	Classification Code Number)	No., if applicable)

Suite 3300, 425 – 1^st Street S.W.
Fifth Avenue Place, East Tower
Calgary, Alberta, Canada T2P 3L8
(403) 237-9400
(Address and telephone number of Registrant’s principal executive offices)

Compton Petroleum Corporation
Compton Petroleum
Compton Petroleum Holdings Corporation
(Exact name of Registrant as specified in its charter)

Alberta, Canada	1311	Not Applicable
(Province or other jurisdiction of	(Primary Standard Industrial	(I.R.S. Employer Identification
incorporation or organization)	Classification Code Number)	No., if applicable)

Suite 3300, 425 – 1^st Street S.W.
Fifth Avenue Place, East Tower
Calgary, Alberta, Canada T2P 3L8
(403) 237-9400
(Address and telephone number of Registrant’s principal executive offices)

Hornet Energy Ltd.
(Exact name of Registrant as specified in its charter)

Canada	1311	Not Applicable
(Province or other jurisdiction of	(Primary Standard Industrial	(I.R.S. Employer Identification
incorporation or organization)	Classification Code Number)	No., if applicable)

Suite 3300, 425 – 1^st Street S.W.
Fifth Avenue Place, East Tower
Calgary, Alberta, Canada T2P 3L8
(403) 237-9400
(Address and telephone number of Registrant’s principal executive offices)

CT Corporation
111 Eighth Avenue
New York, New York 10011
(212) 894-8940
(Name, address and telephone number of agent for service in the United States)

Copies to:

Tim G. Millar	David R.J. Lefebvre	Andrew J. Foley
Compton Petroleum Finance Corporation	Stikeman Elliott LLP	Paul, Weiss, Rifkind,
Suite 3300, 425 – 1st Street S.W.	4300 Bankers Hall West	Wharton & Garrison LLP
Fifth Avenue Place, East Tower	888 – 3rd Street S.W.	1285 Avenue of the Americas
Calgary, Alberta, Canada T2P 3L8	Calgary, Alberta, Canada T2P 5C5	New York, New York 10019-6064
(403) 237-9400	(403) 266-9000	(212) 373-3000

Approximate date of commencement of proposed sale of the securities to the public:
From time to time after the effective date of this Registration Statement.

Province of Alberta, Canada
(Principal jurisdiction regulating this offering)

It is proposed that this filing shall become effective (check appropriate box below):

A.	o		upon filing with the Commission, pursuant to Rule 467(a) (if in connection with an offering being made contemporaneously in the United States and Canada).
B.	þ		at some future date (check appropriate box below)
		1.	o	pursuant to Rule 467(b) on (          ) at (          ) (designate a time not sooner than 7 calendar days after filing).
		2.	o	pursuant to Rule 467(b) on (          ) at (          ) (designate a time 7 calendar days or sooner after filing) because the securities regulatory authority in the review jurisdiction has issued a receipt or notification of clearance on (          ).
		3.	þ	pursuant to Rule 467(b) as soon as practicable after notification of the Commission by the Registrant or the Canadian securities regulatory authority of the review jurisdiction that a receipt or notification of clearance has been issued with respect hereto.
		4.	o	after the filing of the next amendment to this Form (if preliminary material is being filed).

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to the home jurisdiction’s shelf prospectus offering procedures, check the following box.o

     THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE AS PROVIDED IN RULE 467 UNDER THE SECURITIES ACT OF 1933 OR ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SECTION 8(A) OF THE ACT, MAY DETERMINE.

PART I

INFORMATION REQUIRED TO BE DELIVERED
TO OFFEREES OR PURCHASERS

The securities offered hereunder have not been and will not be qualified for sale under the securities laws of Canada and, subject to certain exceptions, may not be offered or sold in Canada. No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise.

SHORT FORM PROSPECTUS

New Issue December 23, 2005

Compton Petroleum Finance Corporation

US$300,000,000
7⁵/₈% Senior Notes due 2013
Unconditionally Guaranteed by
Compton Petroleum Corporation

The Exchange Offer:

• if all of the conditions to this exchange offer (the “Exchange Offer”) are satisfied, we will exchange all 7⁵/₈% Senior Notes due 2013 (the “Initial Notes”) that are validly tendered and not validly withdrawn for an equal principal amount of 7⁵/₈% Senior Notes due 2013 (the “Exchange Notes”) that have been registered under the United States Securities Act of 1933, as amended (the “Securities Act”);

• you may withdraw tenders of Initial Notes at any time prior to the expiration of the Exchange Offer; and

• the Exchange Offer expires at 5:00 p.m., New York City time on February 6, 2006, unless we extend the Exchange Offer.

The Exchange Notes:

• the terms of the Exchange Notes (with the Initial Notes, collectively referred to as the “Notes”) to be issued in the Exchange Offer are substantially identical to the Initial Notes, except that the Exchange Notes will be freely tradable in the United States by persons who are not affiliated with us;

• no public market currently exists for the Initial Notes and we cannot assure you that an active trading market will develop for the Exchange Notes; and

• the Exchange Notes will be guaranteed by Compton Petroleum Corporation and all significant present and future subsidiaries of Compton, other than Compton Petroleum Finance Corporation, (collectively, the “Guarantors”) with respect to the payment of the principal, premium, if any, and interest on the Exchange Notes on an unsecured, unsubordinated basis. The payment obligations of all of Compton’s subsidiaries, including Compton Finance, under the indenture governing the Notes, the Notes and subsidiary guarantees will be guaranteed by Compton Petroleum Corporation on an unsecured, unsubordinated basis.

For a more detailed description of the Notes, see “Description of the Notes” beginning on page 82.

Before participating in the Exchange Offer, please refer to the section in this short form prospectus entitled “Risk Factors” beginning on page 16.

The offering of the Exchange Notes is made by Compton Finance and the offering of the guarantees accompanying the Exchange Notes is made by Compton and its significant wholly-owned subsidiaries other than Compton Finance. Each of these entities is a foreign issuer in the United States and is permitted, under a multijurisdictional disclosure system adopted

by the United States, to prepare this short form prospectus in accordance with the disclosure requirements of Canada. Prospective investors should be aware that such requirements are different from those of the United States. The financial statements included or incorporated herein have been prepared in accordance with Canadian generally accepted accounting principles, and are subject to Canadian auditing and auditor independence standards, and thus may not be comparable to financial statements of United States companies.

Owning the securities described herein may subject you to tax consequences both in the United States and in Canada. This short form prospectus may not describe these tax consequences fully. You should read the tax discussion contained in this short form prospectus.

Neither the United States Securities and Exchange Commission (the “SEC”) nor any United States state securities commission has approved or disapproved of these securities, passed upon the accuracy or adequacy of this short form prospectus or determined if this short form prospectus is truthful or complete. Any representation to the contrary is a criminal offence.

No underwriter has been involved in this short form prospectus or performed any review of the contents of this short form prospectus.

Each broker-dealer that receives Exchange Notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. The Letter of Transmittal states that by so acknowledging 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 by such broker-dealer 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 the Exchange Offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. See “Plan of Distribution.”

TABLE OF CONTENTS

	Page
Documents Incorporated by Reference		ii
Where You Can Find More Information		iii
Enforceability of Civil Liabilities Against Foreign Persons		iii
Presentation of Financial Information		iii
Currency Translation		iv
Presentation of our Reserve Information		iv
Forward-Looking Statements		v
Summary		1
The Exchange Notes		9
Risk Factors		16
Use of Proceeds		29
Capitalization		29
Selected Historical Consolidated Financial Data		30
Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Business		49
Management		63
Related Party Transactions		68
Security Ownership of Beneficial Owners and Management		68
Description of Material Indebtedness and Other Commitments		69
The Exchange Offer		72
Description of the Notes		82
Certain Income Tax Considerations		127
Plan of Distribution		131
Statutory Rights of Withdrawal and Rescission		131
Legal Matters		132
Independent Petroleum Engineers		132
Independent Accountants		132
Glossary of Terms		133
Index to Financial Statements		F-1
Auditor’s Consent		A-1
Certificates		C-1

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DOCUMENTS INCORPORATED BY REFERENCE

     Information has been incorporated by reference in this short form prospectus from documents filed with securities commissions or similar authorities in Canada.Copies of the documents incorporated herein by reference may be obtained on request without charge from the Corporate Secretary of Compton at 425 — 1^st Street S.W., Suite 3300, Calgary, Alberta T2P 3L8 (Telephone: (403) 237-9400) and are also available electronically at www.sedar.com. The following documents of Compton, filed with the various provincial securities commissions or similar authorities in Canada, are specifically incorporated into and form an integral part of this short form prospectus:

(1)	the renewal annual information form of Compton dated March 23, 2005 (the “AIF”);
(2)	the audited consolidated balance sheets of Compton as at December 31, 2004 and 2003, and the audited consolidated statements of earnings, retained earnings and cash flow for each of the years in the three year period ended December 31, 2004, together with the notes thereto and the auditors’ report thereon;
(3)	management’s discussion and analysis of the financial condition and operations of Compton for the years ended December 31, 2004 and 2003;
(4)	the unaudited interim consolidated financial statements of Compton for the nine months ended September 30, 2005 and 2004;
(5)	management’s discussion and analysis of the financial condition and operations of Compton for the nine months ended September 30, 2005 and 2004; and
(6)	the management proxy circular of Compton dated March 4, 2005 (the “Proxy Circular”), relating to the annual general and special meeting of the holders of common shares of Compton held on May 10, 2005 (excluding those portions which appear under the headings ”Performance Graph”, “Report on Executive Compensation” and “Statement of Corporate Governance Practices”).

     Any of the following documents, if filed by Compton with the provincial securities commissions or similar authorities in Canada after the date of this short form prospectus and before the termination of the Exchange Offer, are deemed to be incorporated by reference in this short form prospectus:

(1)	material change reports (except confidential material change reports);
(2)	comparative interim financial statements;
(3)	comparative financial statements for Compton’s most recently completed financial year, together with the accompanying report of the auditor; and
(4)	information circulars (other than any disclosure comparable to those portions of the Proxy Circular which are not incorporated in this short form prospectus).

     Any material change report and any document of the type referred to in the preceding paragraph (excluding confidential material change reports), comparative interim financial statements, comparative annual financial statements together with the auditors’ report thereon, and information circulars filed by Compton with the securities commissions or similar authorities in the provinces of Canada subsequent to the date of this short form prospectus and prior to the termination of this distribution shall be deemed to be incorporated by reference into this short form prospectus.

     The financial results of Compton Finance are included in the consolidated financial statements of Compton which are contained in this short form prospectus.

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     Any statement contained in a document incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this short form prospectus to the extent that a statement contained herein or in any other subsequently filed document which also is, or is deemed to be, incorporated by reference herein modifies or supersedes such statement. The modifying or superseding statement need not state that it has modified or superseded a prior statement or include any other information set forth in the document that it modifies or supersedes. The making of a modifying or superseding statement shall not be deemed an admission for any purposes that the modified or superseded statement, when made, constituted a misrepresentation, an untrue statement of a material fact or an omissions to state a material fact that is required to be stated or that is necessary to make a statement not misleading in light of the circumstances in which it was made. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this short form prospectus.

WHERE YOU CAN FIND MORE INFORMATION

     We have filed a registration statement on Form F-10 with the SEC regarding the Exchange Notes. This short form prospectus is part of our registration statement. For further information about us and the Exchange Notes, you should refer to our registration statement and its exhibits. This short form prospectus summarizes material provisions of contracts and other documents to which we refer you. Since the short form 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.

      Effective December 6, 2005, the date that our common shares began trading on the New York Stock Exchange (“NYSE”), we became subject to the periodic reporting and other informational requirements of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”), and accordingly we are required to file reports and other information with the SEC. Copies of our reports and other information may then be inspected and copied at the public reference facilities maintained by the SEC. 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.

     Copies of our materials filed with the SEC may also be obtained by mail at prescribed rates from the Public Reference Section of the SEC, 100 F Street, N.E., Washington, D.C. 20549 or by calling the SEC at 1-800-SEC-0330. Our filings are also electronically available from the SEC’s Electronic Document Gathering and Retrieval System, which is commonly known by the acronym EDGAR and which may be accessed at www.sec.gov, as well as from commercial document retrieval services.

     We also file information, such as periodic reports and financial information, with the Canadian Securities Administrators, which may be accessed at www.sedar.com.

     Anyone who receives a copy of this short form prospectus may obtain a copy of the indenture governing the Notes without charge by writing to our Corporate Secretary at Suite 3300, 425 – 1^st Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada, TP2 3L8.

ENFORCEABILITY OF CIVIL LIABILITIES AGAINST FOREIGN PERSONS

     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 short form prospectus reside principally in Canada. Because most of these persons are located outside the United States, it may not be possible for you to effect service of process within the United States on these persons. Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in United States 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 Stikeman Elliott LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based upon the United States federal securities laws and as to the enforceability in Canadian courts of judgments of United States courts obtained in actions based upon the civil liability provisions of the United States federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors and officers or some of the experts named in this short form prospectus.

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PRESENTATION OF FINANCIAL INFORMATION

     The financial statements included in this short form prospectus are presented in Canadian dollars. In this short form prospectus, references to “$” or “dollars” are to Canadian dollars and references to “US$” and “U.S. dollars” are to United States dollars. See “Currency Translation” below.

     The financial statements included in this short form prospectus have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Canadian GAAP differs in some material respects from U.S. GAAP, and so these financial statements may not be comparable to the financial statements of U.S. companies. For a discussion of the principal differences between Canadian GAAP and U.S. GAAP as they relate to us, see Note 19 to our consolidated financial statements, which are included elsewhere in this short form prospectus.

     There are certain measures of financial reporting that are used as benchmarks within the oil and natural gas industry that are used in this short form prospectus, including “adjusted earnings from operations”, “Adjusted EBITDA” (and related ratios), “field operating netbacks” and “cash flow netbacks”. The measures discussed are measures of performance, liquidity and value within the industry, and are used by analysts and investors to compare and evaluate natural gas and oil producing entities. These measures are not measures of performance, liquidity or value under Canadian GAAP or U.S. GAAP and should not be considered in isolation or as alternatives to conventional GAAP measures. These measures are not necessarily comparable to similarly titled measures of another company.

CURRENCY TRANSLATION

     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 November 22, 2005, the date we closed the sale of the Initial Notes, the inverse of the noon buying rate in New York City for cable transfers of Canadian dollars was $1.00 = US$.8495.

	Nine Months Ended September 30,				Year Ended December 31,
	2005		2004		2004		2003		2002
High for the period		.7886		.7158		.8493		.7712		.6619
Low for the period		.8615		.7906		.7158		.6349		.6200
End of period		.8615		.7906		.8310		.7738		.6329
Average for the period(1)		.8173		.7505		.7719		.7205		.6370

(1) Average represents the average of the rates on the last day of each month during the period.

PRESENTATION OF OUR RESERVE INFORMATION

     The determination of natural gas and oil reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability, statistics and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions. “Reserves” are estimated remaining quantities of oil, natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on (a) analysis of drilling, geological, geophysical and engineering data; (b) the use of established technology; and (c) specified economic conditions, which are generally accepted as being reasonable and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

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     “Proved” reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Nine out of ten times, the quantities actually recovered will equal or exceed estimated proved reserves. Proved reserves are further classified as follows:

     “developed producing” reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production and the date of resumption of production must be known with reasonable certainty.

     “developed non-producing” reserves are those reserves that either have not been on production, or have previously been on production but are shut-in and the date of resumption of production is unknown.

     “undeveloped” reserves are those reserves expected to be recovered from known accumulations where a significant expenditure, when compared to the cost of drilling a well, is required to render them capable of production. They must fully meet the requirements of the reserves classification to which they are assigned.

     The SEC generally permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves net of royalties and interests of others that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. Canadian securities laws permit oil and gas companies, in their filings with Canadian securities regulators, to disclose reserves and production on a gross basis before deducting royalties. Because we are permitted to prepare this short form prospectus in accordance with Canadian disclosure requirements, we have disclosed in this short form prospectus reserves in accordance with Canadian securities laws, which permit, among other things, reserves to be designated as “gross” in addition to “net” and production on a gross basis before deducting royalties.

“gross” means:

(a)	in relation to a company’s interest in production or reserves, its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the company;
(b)	in relation to wells, the total number of wells in which a company has an interest; and
(c)	in relation to properties, the total area of properties in which a company has an interest.

“net” means:

(a)	in relation to a company’s interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves;
(b)	in relation to a company’s interest in wells, the number of wells obtained by aggregating the company’s working interest in each of its gross wells; and
(c)	in relation to a company’s interest in a property, the total area of properties in which the company has an interest multiplied by the working interest owned by the company.

FORWARD-LOOKING STATEMENTS

     This short form prospectus contains forward-looking statements within the meaning of applicable securities laws. These statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those included in the forward-looking statements. The words “believe”, “expect”,

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“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. These statements are only predictions. Actual events or results may differ materially. In addition, this short form prospectus may contain forward-looking statements attributed to third party industry sources. Undue reliance should not be placed on these forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur.

     Specific forward-looking statements contained in this short form prospectus include, among others, statements regarding:

• our expected financial performance in future periods;

• expected increases in revenues attributable to our exploration and production activities;

• the impact of governmental controls and regulations on our operations;

• our intention to focus on developing long-life natural gas reserves;

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

• drilling plans;

• our plans for reinvesting internally generated cash flow;

• our intention to continue consolidating our position in our core areas;

• our intention to maintain financial flexibility;

• our competitive advantages and ability to compete successfully;

• the size of our hedging program;

• our expansion plans for our properties;

• our reserve estimates and our estimates of the present value of our future net cash flow;

• the factors based on which we will decide whether or not to undertake an exploration or exploitation project;

• our acquisition strategy, the criteria to be considered in connection therewith and the benefits to be derived therefrom; and

• our expectations regarding the exploration, development and production potential of our properties.

     With respect to forward-looking statements contained in this short form prospectus, we have made assumptions regarding, among other things:

• future natural gas and crude oil prices;

• the cost of expanding and maintaining our property holdings;

• our ability to obtain equipment in a timely manner to meet our demand;

• our ability to market natural gas and crude oil successfully to current and new customers;

• the impact of increasing competition; and

• our ability to obtain financing on acceptable terms.

     Some of the risks that could affect our future results and could cause results to differ materially from those expressed in our forward-looking statements include:

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• general economic conditions in Canada, the United States, and generally;

• the volatility of natural gas and crude oil prices;

• the uncertainty of estimates by our independent consultants with respect to our natural gas and crude oil reserves;

• the impact of amendments to theIncome Tax Act(Canada) on us;

• the impact of competition;

• difficulties encountered during the exploration for and production of natural gas and crude oil;

• difficulties encountered in delivering natural gas and crude oil to commercial markets;

• changes in customer demand;

• royalties payable in respect of our natural gas and crude oil production;

• the uncertainty of our ability to attract capital;

• changes in, or the introduction of new, government regulations relating to our natural gas and crude oil business;

• costs associated with exploring for and producing natural gas and crude oil;

• compliance with environmental regulations;

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

• liabilities stemming from accidental damage to the environment;

• stock market volatility and market valuations;

• loss of the services of any of our executive officers; and

• the need to obtain required approvals from regulatory authorities.

     The information contained in this short form prospectus, including the information provided under the heading “Risk Factors”, identifies additional 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 short form 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.

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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 short form prospectus. You should read the entire short form prospectus closely. The terms “Compton”, “Company”, “we”, “our” and “us”, except as otherwise indicated in this short form prospectus or as the context otherwise requires, refer to Compton Petroleum Corporation and its subsidiaries, including Compton Finance, Compton Petroleum Holdings Corporation (“Compton Holdings”), Hornet Energy Ltd. and Compton Petroleum partnership, as a combined entity. The terms “Issuer” and “Compton Finance” refer to Compton Petroleum Finance Corporation, the issuer of the Notes.

Compton

     We are an Alberta-based independent public company actively engaged in the exploration, development and production of natural gas, crude oil and natural gas liquids (“ngls”) in the Western Canadian Sedimentary Basin (the “WCSB”). As of September 30, 2005, we held working interests in 2,501 gross (1,350 net) wells, and as of December 31, 2004, we held working interests in 1,019,854 gross (729,429 net) acres of undeveloped land. As of December 31, 2004, we had established total proved reserves of 97,099 mboe gross (78,767 mboe net) with a PV-10 value of approximately $1 billion. See “Business – Reserves.” Of these reserves, approximately 76% were natural gas reserves and approximately 87% were proved developed reserves. As of December 31, 2004, we operated approximately 88% of our proved reserves.

     We are primarily focused on unconventional natural gas resource plays in the WCSB. Unconventional natural gas reserves include tight gas, coal bed methane (“CBM”) and shale gas. Tight gas reserves are typically abnormally pressured systems that produce little or no water and experience high declines during the first years of production, reducing to very low decline rates thereafter. Compton uses the term resource play to describe an accumulation of hydrocarbons known to exist over a large area and/or a thick vertical section. Resource plays typically include numerous repeatable drilling opportunities and predictable results in terms of production rates and reserves, resulting in lower geological and/or commercial development risk. We are targeting unconventional tight gas, primarily in basin centered gas systems, and coal bed methane resource plays.

     Our exploration, development and exploitation activities are concentrated principally in three core areas:

• Southern Alberta.As of December 31, 2004, we held approximately 492,655 gross (397,799 net) acres of undeveloped land in southern Alberta. Our activities target unconventional natural gas reserves in the Plains Belly River, Horseshoe Canyon Edmonton coal bed methane, Hooker Basal Quartz, thrusted foothills Belly River (Callum) and Wabamun/Crossfield formations. The area is prospective for multiple gas-charged zones. In 2004, we drilled 101 gross (88 net) wells in southern Alberta with a 92% success rate. From January 1 to September 30, 2005, we drilled 135 gross (127 net) wells in southern Alberta with a 99% success rate.

• Central Alberta. As of December 31, 2004, we held approximately 256,454 gross (164,568 net) acres of undeveloped land in central Alberta, the majority of which is located approximately 100 kilometres west of Edmonton. Our central Alberta operations target unconventional natural gas reserves of a similar nature to our reserves in the Hooker Basal Quartz formation in southern Alberta. In 2004, we drilled 46 gross (32 net) wells in central Alberta with an 83% success rate. From January 1 to September 30, 2005, we drilled 55 gross (27 net) wells in central Alberta with a 100% success rate.

• Peace River Arch. As of December 31, 2004, we held approximately 117,040 gross (76,384 net) acres of undeveloped land in the Peace River Arch area. The Peace River Arch area contains multi-zone potential for exploration and development opportunities. This area includes both light oil production at Cecil/Worsley and opportunities for natural gas exploration at

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Howard and Pouce Coupe. In 2004, we drilled 39 gross (26 net) wells in the Peace River Arch area with a 92% success rate. From January 1, to September 30, 2005, we drilled 85 gross (78 net) wells in the Peace River Arch area with an 86% success rate.

     The following table summarizes our average daily production, before deducting royalties, from our core areas for the year ended December 31, 2004:

					Natural Gas
	Natural Gas		Crude Oil		Liquids		Total
	(mcf/d)		(bbls/d)		(bbls/d)		(boe/d)
Southern Alberta		78,256		143		1,428		14,614
Central Alberta		25,231		1,356		509		6,070
Peace River Arch		16,693		2,613		158		5,553
Total		120,180		4,112		2,095		26,237

Competitive Strengths and Operating Strategies

     Our plan is to grow our reserves and optimize the economic recovery of reserves from our core areas and other areas where we have technical expertise. We aim to achieve this objective by focusing on the efficient exploration, development and exploitation of our properties, controlling operating costs, adding economic reserves and production and making strategic acquisitions in our core areas. We believe that our experienced management, and professional, technical and support staff are well suited to carry out our business plan and our current exploration, development, exploitation, production, engineering, financial and administrative functions.

     Our operating strategy includes the following components:

     Concentrate on Core Areas. We focus on our core areas, which provide us with a balanced portfolio of exploration, development and exploitation prospects. These areas are the geographic focus of our seismic database rights, and are areas in which our management and staff have significant technical expertise and operational experience. Our intention is to generate exploration opportunities and to increase our undeveloped land base within the WCSB.

     Focus on Unconventional Natural Gas in Large Resource Plays. As of December 31, 2004, approximately 76% of our proved reserves were natural gas, of which approximately 75% were unconventional natural gas reserves. We have gained considerable technical expertise and achieved significant success in exploring for unconventional, larger natural gas accumulations in the WCSB. We plan to continue to focus on finding and developing these types of natural gas opportunities because of their generally lower decline curves and higher economic return over the life of the reserves compared to conventional natural gas opportunities. The large scale nature of our resource plays also offers multiple low-risk drilling locations resulting in lower costs and decreased exploration risk.

     Pursue Growth Through the Drill Bit Complemented by Selective Acquisitions. We plan to continue to reinvest internally generated cash flow and to use other sources of capital to fund the growth of our exploration and development programs and to further increase our undeveloped land base to maintain a growing inventory of drilling prospects in our core areas. In 2004,we began an accelerated drilling program. Based on our plans for an annual 500 to 700 gross well drilling program, we have over five years of drilling inventory on our existing lands. Most of these planned wells are expected to be in close proximity to producing wells in our existing core areas. Our drilling success rate has been at or above 90% for each of the past three years, giving us confidence in our ability to successfully grow reserves and production from our extensive inventory of drilling locations.

     Control 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 critical infrastructure in each of our three core areas. As of December 31, 2004, we operated approximately 88% of our proved reserves and had a 72% average

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working interest in our undeveloped lands. Being an operator allows us to exercise discretion in determining the timing and methodology of our ongoing exploration, development and exploitation programs. We expect to continue to expand our working interest in our core areas to maximize these operating efficiencies.

     Maintain Financial Flexibility. We are committed to maintaining financial flexibility sufficient to allow us to pursue our full-cycle exploration program in periods of low commodity prices and to respond to opportunities for strategic acquisitions as they arise. We have historically funded our exploration, development and exploitation capital program through internally generated cash flow and have financed acquisitions through bank debt, the issuance of common shares or a combination thereof. Our accelerated drilling program has recently been, and will continue to be, funded through internally generated cash flow, the issuance of additional equity and debt, and non-core property sales. Other components of our financial discipline include establishing appropriate leverage ratios and maintaining an active commodity hedging program.

Recent Developments

     We drilled 147 gross (123 net) wells in the third quarter of 2005 for a total of 277 gross (233 net) wells drilled from January 1 to September 30, 2005, including 2 gross (1 net) standing, cased wells. With 14 drilling rigs at work as of September 30, 2005, we are the eighth most active operator in western Canada.

     We have experienced abnormally wet weather conditions in southern Alberta in 2005. These conditions have interrupted and delayed our well completions, pipeline construction and tie-ins. These delays have, in turn, impacted production growth. We now expect average production for 2005 to be in the range of 30,000 to 31,000 boe/d as compared to an original projection of 31,500 to 32,500 boe/d. December 2005 production is now estimated to be in the range of 35,500 to 37,500 boe/d compared to our previous estimate of 36,500 to 37,500 boe/d. We are currently producing approximately 31,000 boe/d.

     We are currently working to bring in excess of 6,000 boe/d of behind pipe production on-line as quickly as possible. Despite these wet weather conditions, we completed our 390 well drilling program this year.

     On November 22, 2005, we sold US$300 million aggregate principal amount of senior term notes, the Initial Notes, which bear interest semi-annually, in arrears on December 1 and June 1 of each year, at a rate of 7⁵/₈% per year with principal repayable on December 1, 2013. We intend to exchange the Initial Notes for the Exchange Notes. On November 22, 2005, Compton Holdings purchased US$158,250,000 aggregate principal amount of 9.90% senior notes of Compton due 2009 (the “9.90% Notes”) pursuant to a tender offer which expired on November 29, 2005. On May 15, 2006, we expect to redeem the US$6.75 million aggregate principal balance of 9.90% Notes not tendered in the tender offer. See “Description of Material Indebtedness and Other Commitments” and “The Exchange Offer”.

Corporate Structure

     Compton Petroleum Corporation was incorporated by articles of incorporation pursuant to the provisions of theBusiness Corporations Act(Alberta) on October 15, 1992, and we commenced active business operations in July 1993. Our head and principal office is located at Suite 3300, 425 - 1^st Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada, T2P 3L8. Our general telephone number is (403) 237-9400. Our common shares are listed and posted for trading on the Toronto Stock Exchange (“TSX”) under the trading symbol “CMT”. Our common shares began trading on the New York Stock Exchange on December 6, 2005 under the ticker symbol “CMZ”.

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

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     Compton Finance is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Finance has no independent operations and has no significant liabilities or assets other than the Notes, its equity interest in Hornet Energy Ltd. and intercorporate indebtedness. The registered office of Compton Finance is 4300 Bankers Hall West, 888 – 3^rd Street S.W., Calgary, Alberta, Canada T2P 5C5.

     Compton Holdings is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Holdings has no independent operations and has no significant liabilities or assets other than owning US$158,250,000 aggregate principal amount of 9.90% Notes and intercorporate indebtedness. The registered office of Compton Holdings is 4300 Bankers Hall West, 888 – 3^rd Street S.W., Calgary, Alberta, Canada T2P 5C5.

     The following chart shows our corporate structure, including significant subsidiaries.

(1)	Compton Petroleum Corporation, Compton Holdings, Hornet Energy Ltd. and Compton Petroleum partnership will be guarantors of the Exchange Notes upon completion of this offering.
(2)	Reflects ownership as of September 30, 2005. Ownership is determined semi-annually based on value of assets contributed.

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The Exchange Offer

     On November 22, 2005, the Issuer sold its Initial Notes in a private placement exempt from the registration requirements of the Securities Act and exempt from applicable prospectus requirements under Canadian securities laws, and Credit Suisse First Boston LLC, Morgan Stanley & Co. Incorporated, Harris Nesbitt Corp., Hibernia Southcoast Capital, Inc., Scotia Capital (USA), Inc. and TD Securities (USA) LLC as initial purchasers of these Initial Notes (the “Initial Purchasers”) then resold them in reliance on other exemptions from the registration requirements of the Securities Act and such prospectus exemptions. Consequently, the Initial Notes are subject to transfer restrictions under applicable securities laws. Pursuant to the terms of a registration rights agreement entered into by the Issuer, the Guarantors and the Initial Purchasers on November 22, 2005 (the “Registration Rights Agreement”), the Issuer and the Guarantors agreed, among other things, to deliver this short form prospectus, and to file a registration statement (the “Exchange Offer Registration Statement”) with the SEC with respect to a proposed offer, the Exchange Offer, to the holders of the Initial Notes who are not prohibited by law or policy of the SEC from participating in the Exchange Offer, and to issue and deliver to such holders, in exchange for the Initial Notes, the Exchange Notes that would be registered under the Securities Act.

     The Issuer and the Guarantors agreed to keep the Exchange Offer Registration Statement effective for not less than 30 days (or longer if required by applicable law) after the date notice of the Exchange Offer is mailed to the holders of the Initial Notes. In addition, the Issuer and the Guarantors agreed in the event that (i) the Issuer and the Guarantors determine that the Exchange Offer is not available or may not be consummated because it would violate applicable law or the applicable interpretations of the staff of the SEC, (ii) the Exchange Offer is not for any other reason completed by the 20^th day following the consummation of the Exchange Offer or (iii) the Exchange Offer has been completed and in the opinion of counsel for the Initial Purchasers an Exchange Offer Registration Statement must be filed and a prospectus must be delivered by the Initial Purchasers in connection with any offering or sale of the Exchange Notes, they shall use their commercially reasonable efforts to cause to be filed as soon as practicable after such determination, date or notice of such opinion of counsel is given to the Issuer and the Guarantors, as the case may be, a shelf registration statement (the “Shelf Registration Statement”) providing for the sale by the holders of all of the Exchange Notes and to have such Shelf Registration Statement declared effective by the SEC.

     As holders of the Initial Notes you are entitled to exchange in the Exchange Offer your Initial Notes for Exchange Notes, which are identical in all material respects to the Initial Notes except that:

• in the event the Exchange Offer is not completed or the Shelf Registration Statement is not declared effective on or prior to May 21, 2006, additional interest on the Initial Notes will be paid by the Issuer until the Exchange Offer is completed or the Shelf Registration Statement is declared effective by the SEC (see “The Exchange Offer – Purpose and Effect of the Exchange Offer”);

• the Exchange Notes have been registered under the Securities Act and will be freely tradable by persons who are not affiliated with us; and

• the Exchange Notes are not entitled to the rights that are applicable to the Initial Notes under the Registration Rights Agreement.

This summary describes the principal terms of the offering. Some of the terms and conditions described below are subject to important limitations and exceptions. You should carefully read the “Description of the Notes” section of this short form prospectus for a more detailed description of the Exchange Offer.

The Exchange Offer: We are offering to exchange up to US$300,000,000 aggregate principal amount of our Exchange Notes for up to US$300,000,000 aggregate principal amount of our Initial Notes, which were issued on November 22, 2005 in a private placement. Initial Notes may be exchanged for Exchange Notes only in integral multiples of US$1,000.

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Resale of the Exchange Notes:	Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the Exchange Notes issued in the Exchange Offer may be offered for resale, resold and otherwise transferred by you (unless you are our “affiliate” within the meaning of Rule 405 under the Securities Act) in the United States without compliance with the registration and prospectus delivery requirements of the Securities Act, provided that you are:
	•	acquiring the Exchange Notes in the ordinary course of business;
	•	not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the Exchange Notes; and
	•	not a broker-dealer who purchased your Initial Notes directly from us for resale pursuant to Rule 144A (“Rule 144A”) under the Securities Act or any other available exemption under the Securities Act.
	We do not intend to seek our own no-action letter from the SEC, and there is no assurance that the SEC staff would make a similar determination with respect to the Exchange Notes. If this interpretation is inapplicable and you transfer any Exchange Notes issued to you in the Exchange Offer without delivering a prospectus or without an exemption under the Securities Act, you may incur liability under the Securities Act. We do not assume or indemnify you against this liability.
	Each broker-dealer that receives Exchange Notes for its own account in exchange for the Initial Notes that were acquired by this 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 those Exchange Notes. See “Plan of Distribution.” Any holder of Initial Notes who:
	•	is our “affiliate” as defined in Rule 405 under the Securities Act;
	•	does not acquire the Exchange Notes in the ordinary course of business;
	•	tenders in the Exchange Offer with the intention to participate, or for the purpose of participating, in a distribution of the Exchange Notes; or
	•	is a broker-dealer that purchased Initial Notes from us to resell them pursuant to Rule 144A or any other available exemption under the Securities Act,
	cannot rely on the position of the SEC staff expressed in the no- action letters described above and, in the absence of an exemption, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of the Exchange Notes.
Expiration of Exchange Offer:	The Exchange Offer will expire at 5:00 p.m., New York City time, on February 6, 2006, unless we decide to extend the expiration date.
Withdrawal Rights:	You may withdraw the tender of your Initial Notes at any time prior to 5:00

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	p.m., New York City time, on the expiration date.
Accrued Interest on the Exchange Notes and Initial Notes:	The Exchange Notes will bear interest from the most recent date to which interest has been paid on the Initial Notes or, if no interest has been paid on the Initial Notes, from November 22, 2005.
Conditions to the Exchange Offer:	The Exchange Offer is subject to customary conditions, some of which we may waive. See “The Exchange Offer — Conditions to the Exchange Offer.”
Procedures for Tendering Initial Notes:	If you wish to exchange your Initial Notes for Exchange Notes pursuant to the Exchange Offer, you must complete, sign and date the letter of transmittal according to the instructions contained in this short form prospectus and the letter of transmittal. You must also mail or otherwise deliver the letter of transmittal, together with your Initial Notes and any other required documents, to The Bank of Nova Scotia Trust Company of New York (the “Exchange Agent”) at the address set forth on the cover of the letter of transmittal. If you hold Initial Notes through The Depository Trust Company (the “DTC”) and wish to participate in the Exchange Offer, you must comply with the Automated Tender Offer Program procedures of DTC, by which you will agree to be bound by the letter of transmittal. By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:
	•	you are acquiring the Exchange Notes in the ordinary course of business;
	•	you are not engaged in, and do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the Exchange Notes;
	•	if you are a broker-dealer that will receive Exchange Notes for your own account in exchange for Initial Notes that were acquired as a result of market-making or other trading activities, you will deliver a prospectus, as required by law, in connection with any resale of the Exchange Notes; and
	•	you are not our “affiliate” as defined in Rule 405 under the Securities Act.
	See “The Exchange Offer — Procedures for Tendering Initial Notes.”
Special Procedures for Beneficial Owners:	If you own a beneficial interest in Initial Notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee or custodian, and you wish to tender your Initial Notes in the Exchange Offer, you should contact the registered holder as soon as possible and instruct the registered holder to tender on your behalf.
Guaranteed Delivery Procedures:	If you wish to tender your Initial Notes and your Initial Notes are not immediately available or you cannot deliver your Initial Notes, the letter of transmittal or any other documents required by the letter of transmittal to the Exchange Agent or comply with the applicable procedures under DTC’s Automated Tender Offer Program by the expiration date, you must tender your Initial Notes pursuant to the guaranteed delivery procedures described in this short form prospectus under the heading “The Exchange Offer – Procedures for Tendering Initial Notes – Guaranteed Delivery Procedures.”

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Consequences of Failure to Exchange the Initial Notes for the Exchange Notes:	All unexchanged Initial Notes will continue to be subject to transfer restrictions. In general, the Initial Notes may not be offered or sold unless registered under the Securities Act or pursuant to an exemption from registration under the Securities Act and applicable state securities laws. Therefore, the market for secondary resales of any unexchanged Initial Notes is likely to be minimal. Other than in connection with the Exchange Offer, we do not currently anticipate that we will register the Initial Notes under the Securities Act.
Federal Income Tax Consequences:	The exchange of the Initial Notes for the Exchange Notes will generally not be a taxable event for U.S. federal income tax purposes. See “Certain Income Tax Considerations — United States Federal Income Tax Consequences.”
Use of Proceeds:	We will not receive any cash proceeds from the issuance of the Exchange Notes in the Exchange Offer. We will pay all expenses incident to the Exchange Offer. See “Use of Proceeds” and “The Exchange Offer — Fees and Expenses.”
Exchange Agent for Notes:	The Bank of Nova Scotia Trust Company of New York is the Exchange Agent for the Exchange Offer.

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THE EXCHANGE NOTES

The following summary is provided solely for your convenience. This summary is not intended to be complete. For a more detailed description of the Exchange Notes, see “Description of the Notes”.

Issuer	Compton Petroleum Finance Corporation.
Notes Offered	US$300 million aggregate principal amount of 75/8% Senior Notes due December 1, 2013.
Maturity Date	December 1, 2013.
Interest	75/8% per year. The Issuer will make interest payments in U.S. dollars.
Interest Payment Dates	June 1 and December 1, beginning on June 1, 2006.
Subsidiary Guarantees	The Exchange Notes will be initially guaranteed by all of our subsidiaries (except the Issuer, Compton Petroleum (U.S.A.) Corporation and Redwood Energy (U.S.A.) Ltd.) with respect to the payment of principal, premium, if any, and interest on the Exchange Notes on a senior unsecured basis. Each of our subsidiary guarantors and the Issuer also guarantees our senior secured credit facilities on a senior secured basis.
Parent Guarantee	The payment obligations of our subsidiaries, including the Issuer, under the indenture, the Exchange Notes and the subsidiary guarantees will be guaranteed by Compton Petroleum Corporation on a senior unsecured basis.
Mandatory Redemption	The Issuer will not be required to make mandatory redemption or sinking fund payments with respect to the Exchange Notes.
Optional Redemption	The Issuer may redeem the Exchange Notes in whole or in part at any time on or after December 1, 2009, at the redemption prices described under the heading “Description of the Notes — Optional Redemption”. Prior to December 1, 2008, the Issuer may redeem up to 35% of the Exchange Notes with the proceeds of certain equity offerings, provided at least 65% of the aggregate principal amount of the Exchange Notes under the indenture remains outstanding after the redemption and subject to limitations contained in our senior secured credit facilities.
Additional Amounts and Redemption for Changes in Canadian Withholding Taxes	The Issuer will make payments on the Exchange Notes free of withholding or deduction for Canadian taxes. If withholding or deduction is required, the Issuer 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, the Issuer is required to pay such additional amounts, the Issuer may redeem the Exchange 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.
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 Exchange 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 Exchange Notes and the guarantees will be:

• unsecured;

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		•	equal in right of payment to the Issuer’s and to the parent’s and subsidiary guarantors’ current and future unsecured senior indebtedness;
		•	senior in right of payment to the Issuer’s and to the parent’s and subsidiary guarantors’ future debt that expressly provides for subordination to the Exchange Notes or the guarantees; and
		•	effectively subordinated to all existing and any future secured indebtedness of the Issuer and the parent and subsidiary guarantors to the extent of the assets securing such indebtedness, which indebtedness includes our senior secured credit facilities, which are secured by substantially all of the Issuer’s, parent’s and the subsidiary guarantors’ assets.
Certain Covenants	The indenture governing the Exchange Notes will limit our ability and that of our restricted subsidiaries to, among other things:
		•	incur additional indebtedness and issue preferred stock;
		•	create liens;
		•	make restricted payments;
		•	create or permit to exist restrictions on our ability or the ability of our restricted subsidiaries to make certain payments and distributions;
		•	engage in amalgamations, mergers or consolidations;
		•	make certain dispositions and transfers of assets; and
		•	engage in transactions with affiliates.
	These covenants are subject to important exceptions and qualifications, which are described under “Description of the Notes – Certain Covenants” in this short form prospectus.

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Summary Historical Financial Data

     The table set forth below provides our summary financial data for the twelve months ended September 30, 2005, each of the nine-month periods ended September 30, 2005 and 2004 and each of the years ended December 31, 2004, 2003 and 2002. The financial data for each of the years ended December 31, 2004, 2003 and 2002 have been derived from our audited consolidated financial statements for those years, included elsewhere in this short form prospectus, which were audited by Grant Thornton LLP, independent accountants.

     The financial data for each of the nine-month periods ended September 30, 2005 and 2004 have been derived from our unaudited consolidated financial statements for those periods, included elsewhere in this short form prospectus. The unaudited consolidated financial statements for those periods have been prepared on the same basis as our audited consolidated financial statements except as disclosed in the notes to those financial statements, included elsewhere in this short form prospectus. Our management believes that the unaudited consolidated financial statements for those periods contain all adjustments necessary for a fair presentation of the financial information presented (consisting only of normal recurring adjustments). The financial data for the interim periods are not necessarily indicative of the results that may be expected for our full year of operations.

     Our financial statements have been prepared in accordance with Canadian GAAP, which differs in some material respects from U.S. GAAP. For a discussion of the principal differences between U.S. GAAP and Canadian GAAP, you should read Note 19 to our consolidated financial statements included elsewhere in this short form prospectus. Although we do not own the equity of Mazeppa Processing Partnership (“MPP”), through a management agreement we manage the activities of MPP and are considered to be the primary beneficiary of MPP’s operations. As a result, our consolidated financial statements include the assets, liabilities and operations of MPP. See Note 4 to our consolidated financial statements.

     This summary financial data should be read along with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the related notes included elsewhere in this short form prospectus.

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	Twelve
	Months
	Ended			Nine Months Ended
	September 30,			September 30,						Year Ended December 31,
	2005(1)			2005			2004			2004			2003			2002
				(in thousands of Canadian dollars, except ratios)
Canadian GAAP
Statement of Earnings Data:
Revenue:
Natural gas and oil revenues	$	474,640		$	373,451		$	290,470		$	391,659		$	346,565		$	226,597
Royalties		(114,680	)		(89,193	)		(67,929	)		(93,416	)		(82,566	)		(47,497	)
Net revenue		359,960			284,258			222,541			298,243			263,999			179,100
Expenses:
Operating		63,564			47,873			39,964			55,655			49,916			45,546
Transportation		10,276			7,740			6,059			8,595			8,447			8,167
General and administrative		19,239			14,359			10,335			15,215			12,206			9,845
Interest and finance charges		33,018			24,210			24,925			33,733			30,595			23,197
Depletion and depreciation		98,807			74,499			58,246			82,554			61,749			55,473
Foreign exchange (gain) loss		(16,965	)		(7,006	)		(4,672	)		(14,631	)		(47,368	)		1,583
Accretion of asset retirement obligations		1,825			1,416			1,261			1,670			1,436			1,241
Stock-based compensation		4,965			4,254			2,699			3,410			793			190
Risk management (gain) loss		34,331			36,110			10,587			8,808			4,132			(4,424	)
Total expenses		249,060			203,455			149,404			195,009			121,906			140,818
Earnings before income taxes and non-controlling interest		110,900			80,803			73,137			103,234			142,093			38,282
Income taxes		44,238			32,530			24,475			36,183			23,323			19,970
Earnings before non-controlling interest		66,662			48,273			48,662			67,051			118,770			18,312
Non-controlling interest		7,065			5,053			1,406			3,418			(110	)		—
Net Earnings	$	59,597		$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Cash Flow Data:
Cash provided (used) by:
Operating activities(2)	$	216,944		$	185,104		$	132,697		$	164,537		$	156,211		$	90,906
Investing activities		(363,281	)		(300,336	)		(218,251	)		(281,196	)		(276,831	)		(154,138	)
Financing activities(2)		149,520			122,064			83,723			111,179			121,443			72,905
Other Financial Data:
Adjusted EBITDA(3)(4)	$	251,861		$	204,176		$	157,336		$	205,021		$	186,802		$	118,535
Ratio of Adjusted EBITDA to interest expense(5)		8.2	x		9.1	x					6.6	x		6.6	x		5.6	x
Pro forma interest expense(6)	$	35,218
Ratio of Adjusted EBITDA to pro forma interest expense(7)		7.7	x
Balance Sheet Data (at period end):
Total assets(8)				$	1,607,141		$	1,252,430		$	1,330,611		$	1,064,320
Long-term debt(9)					451,582			392,543			418,594			377,746
Shareholders’ equity					557,041			408,909			424,078			356,906
U.S. GAAP
Net earnings	$	60,533		$	43,978		$	49,314		$	65,869		$	98,031		$	22,055
Adjusted EBITDA(3)(4)		251,861			204,176			157,336			205,021			181,121			118,704
Ratio of Adjusted EBITDA to interest expense(5)		8.2	x		9.1	x					6.6	x		6.4	x		5.6	x
Pro forma interest expense(6)	$	35,218
Ratio of Adjusted EBITDA to pro forma interest expense(7)		7.7	x

(1) The financial data for the twelve months ended September 30, 2005 is derived from our audited consolidated financial statements for the year ended December 31, 2004 and our unaudited consolidated financial statements for the nine months ended September 30, 2005 and 2004.

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(2)	Cash provided (used) by operating activities includes cash provided by MPP, to which we are not entitled because we do not have an ownership interest in MPP. Cash provided (used) by financing activities includes cash used for distributions to the partners of MPP. See Note 4 to our consolidated financial statements included elsewhere in this short form prospectus and “Description of Material Indebtedness and Other Commitments – Mazeppa Processing Partnership and Related Agreements”.
(3)	Adjusted EBITDA is calculated as net earnings before interest and finance charges, depletion and depreciation, unrealized foreign exchange gains and losses, stock-based compensation, unrealized risk management gains and losses and income taxes and less “MPP related adjustments”, which represents depletion and depreciation and income taxes attributable to MPP. Adjusted EBITDA is not a measure of operating performance or liquidity under Canadian or U.S. GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets. We have included information concerning Adjusted EBITDA because we consider it an important supplemental measure of our performance. However, viewing Adjusted EBITDA as an indicator of our operating performance should be done with caution. Adjusted EBITDA should not be considered in isolation of, or more meaningful than, net earnings or cash provided by operating activities as determined in accordance with Canadian or U.S. GAAP. Adjusted EBITDA is not necessarily comparable to a similarly titled measure of another company.
(4)	The following table reconciles net earnings to Adjusted EBITDA:

	Twelve
	Months
	Ended			Nine Months Ended
	September 30,			September 30,						Year Ended December 31,
	2005			2005			2004			2004			2003			2002
	(in thousands of Canadian dollars)
Canadian GAAP
Net Earnings:	$	59,597		$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Add (deduct)
Interest and finance charges		33,018			24,210			24,925			33,733			30,595			23,197
Depletion and depreciation		98,807			74,499			58,246			82,554			61,749			55,473
Unrealized foreign exchange (gain) loss		(16,961	)		(7,012	)		(4,703	)		(14,652	)		(47,388	)		1,583
Stock-based compensation		4,965			4,254			2,699			3,410			760			—
Unrealized risk management (gain) loss		31,025			34,930			6,084			2,179			—			—
Income taxes		44,238			32,530			24,475			36,183			23,323			19,970
MPP related adjustments		(2,828	)		(2,455	)		(1,646	)		(2,019	)		(1,117	)		—
Adjusted EBITDA	$	251,861		$	204,176		$	157,336		$	205,021		$	186,802		$	118,535
U.S. GAAP
Net Earnings:	$	60,533		$	43,978		$	49,314		$	65,869		$	98,031		$	22,055
Add (deduct)
Interest and finance charges		33,018			24,210			24,925			33,733			30,595			23,197
Depletion and depreciation		98,807			74,499			58,246			82,554			61,749			54,931
Unrealized foreign exchange (gain) loss		(16,961	)		(7,012	)		(4,703	)		(14,652	)		(47,388	)		1,583
Stock-based compensation		4,965			4,254			2,699			3,410			760			—
Unrealized risk management (gain) loss		28,884			33,699			3,351			(1,464	)		24,296			(8,659	)
Income taxes		45,443			33,003			25,150			37,590			14,195			25,597
MPP related adjustments		(2,828	)		(2,455	)		(1,646	)		(2,019	)		(1,117	)		—
Adjusted EBITDA	$	251,861		$	204,176		$	157,336		$	205,021		$	181,121		$	118,704

(5)	For purposes of computing the ratio of Adjusted EBITDA to interest expense, interest expense excludes the amortization of debt issuance costs.
(6)	Pro forma interest expense gives effect to the transactions as described under “Use of Proceeds” assuming the transactions closed on September 30, 2004 and using an interest rate on the Notes of 75/8% and an average Canadian / U.S. exchange rate for the period of US$1.00 = $1.2231.
(7)	For purposes of computing the ratio of Adjusted EBITDA to pro forma interest expense, pro forma interest expense excludes the amortization of debt issuance costs.
(8)	Total assets include the assets of MPP, in which we do not have an ownership interest.
(9)	Long-term debt includes current portion of long-term debt.

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Summary Reserves and Undeveloped Land Data

     The table set forth below summarizes our natural gas, crude oil, natural gas liquids and sulphur reserves and undeveloped land as of the dates indicated and the present value attributable to these reserves as of those dates, discounted at 10% using constant pricing. The reserve information as of December 31, 2004 and December 31, 2003 was evaluated in reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (“NSAI”). The reserve information as of December 31, 2002 was evaluated in a report dated January 1, 2003, prepared by Outtrim Szabo Associates Ltd. (now DeGolyer and MacNaughton Canada Limited), independent petroleum engineers (“Outtrim”).

     Reserve engineering is a subjective process of estimating and evaluating underground accumulations of natural gas, crude oil and natural gas liquids that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by petroleum engineers. In addition, the results of drilling, testing and production activities may require revisions of reserve estimates that were made previously. Accordingly, estimates of reserves and their value are inherently imprecise and are subject to constant revision and change, and they should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and gas properties or the fair market value of such properties.

	Historical as of December 31,
	2004						2003						2002
	Gross			Net			Gross			Net			Gross			Net
Proved Reserves:
Natural gas (mmcf)		445,422			359,975			404,539			326,573			401,844			314,501
Crude oil & natural gas liquids (mbbls)		21,211			17,327			15,907			12,919			13,805			10,723
Sulphur (mlt)		1,651			1,444			1,853			1,623			4,660			3,883
Natural gas equivalent (mmcfe)		582,591			472,603			511,099			413,825			512,634			402,139
Barrel of oil equivalent (mboe)		97,099			78,767			85,183			68,971			85,439			67,023
% natural gas		76.5	%		76.2	%		79.2	%		78.9	%		78.4	%		78.2	%
% proved developed		86.6	%		86.9	%		86.1	%		87.0	%		94.0	%		94.4	%
Estimated reserve life (years)(1)		9.9			10.5			9.1			9.7			8.9			9.2
Annual reserve replacement percentage(2)		221	%					97	%					249	%
Recycle ratio(3)		1.6	x					1.1	x					1.7	x
PV-10 (thousands)(4)				$	1,000,772					$	759,083					$	1,016,120
Undeveloped Land:
Undeveloped land (thousands of acres)		1,019			729			1,043			767			1,043			743

(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 percentage is determined by dividing our estimated proved reserves added during a year from exploration, development and exploitation 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 determined by dividing our field operating netback per boe in a year by our finding and development costs per boe in that year. Field operating netback per boe is calculated by dividing our annual net revenues generated from producing natural gas, and crude oil and natural gas liquids volumes, net of operating costs and transportation expenses by our annual production in that year. Finding and development costs per boe is calculated by dividing our exploration and development costs incurred in a year and the change in future development costs relating to proved reserves by the additions to proved reserves made during that year. Finding and development costs do not include capital expenditures made by MPP.
(4)	“PV-10” is the present value of our estimated future net cash flows from proved reserves before income taxes, discounted at 10% per year, calculated using constant pricing. The prices used in 2002 were $6.00 per mcf of natural gas and $46.91 per barrel of crude oil and natural gas liquids. The prices used in 2003 were $6.09 per mcf of natural gas and $41.05 per barrel of crude oil and natural gas liquids. The prices used in 2004 were $6.79 per mcf of natural gas and $40.28 per barrel of crude oil and natural gas liquids. PV-10 does not purport to present the fair market value of our natural gas and crude oil and natural gas liquids properties and is not necessarily indicative of actual future cash flows.

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Summary Operating Data

     The following table provides summary data with respect to our production, before deducting royalties, and sales of natural gas, and crude oil and natural gas liquids for the periods indicated and the costs related to such production.

	Nine Months Ended September 30,				Year Ended December 31,
	2005		2004		2004		2003(1)		2002
Production:
Natural gas (mmcf)		35,459		33,395		45,120		42,990		40,807
Crude oil and natural gas liquids (mbbls)		1,974		1,676		2,317		2,162		2,374
Natural gas equivalent (mmcfe)		47,303		43,451		59,021		55,963		55,049
Barrel of oil equivalent (mboe)		7,884		7,242		9,837		9,327		9,175
Average Sales Price Per Unit(2)(3):
Natural gas (per mcf)	$	7.46	$	6.52	$	6.46	$	6.27	$	3.80
Crude oil and natural gas liquids (per bbls)	$	55.24	$	43.33	$	43.21	$	35.59	$	30.06
Natural gas equivalent (per mcfe)	$	7.89	$	6.69	$	6.64	$	6.19	$	4.12
Barrel of oil equivalent (per boe)	$	47.37	$	40.11	$	39.82	$	37.16	$	24.70
Costs:
Royalties (per mcfe)	$	1.89	$	1.56	$	1.58	$	1.48	$	0.86
Royalties (per boe)	$	11.31	$	9.38	$	9.50	$	8.85	$	5.18
Operating (per mcfe)(3)	$	1.01	$	0.92	$	0.94	$	0.89	$	0.83
Operating (per boe)(3)	$	6.07	$	5.52	$	5.66	$	5.35	$	4.96
Transportation (per mcfe)	$	0.16	$	0.14	$	0.15	$	0.15	$	0.15
Transportation (per boe)	$	0.98	$	0.84	$	0.87	$	0.91	$	0.89
General and administrative (per mcfe)(4)	$	0.30	$	0.24	$	0.26	$	0.22	$	0.18
General and administrative (per boe)(4)	$	1.82	$	1.43	$	1.55	$	1.31	$	1.07

(1)	2003 costs have been restated to include the impact of the consolidation of MPP. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Consolidation of Mazeppa Processing Partnership”.
(2)	Excludes the impact of hedging transactions. 2003 and 2002 amounts have been reclassified to exclude hedge gains and losses.
(3)	Prior to 2004, transportation costs were partially recorded as a reduction of revenue and partially recorded as an increase in operating expense. 2003 and 2002 amounts have been reclassified to exclude transportation charges.
(4)	Excludes stock-based compensation.

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RISK FACTORS

     Before you decide to participate in the Exchange Offer, you should carefully consider the following risk factors and other information contained in this short form prospectus.

     Risks Related to our Business

Natural gas and crude oil prices are volatile and low prices will adversely affect our business.

     Fluctuations in the prices of natural gas and crude oil will affect many aspects of our business, including:

• our revenues, cash flows and earnings;

• our ability to attract capital to finance our operations and future growth;

• our cost of capital;

• the amount we are allowed to borrow under our senior secured credit facilities; and

• the value of our natural gas and crude oil properties.

     Both natural gas and crude oil prices have historically been extremely volatile as well as seasonal and cyclical. The average prices that we currently receive for our production are significantly higher than their historic average. Among the factors that can cause natural gas and crude oil price fluctuation are:

• the level of consumer product demand;

• the domestic and foreign supply of natural gas and crude oil, including the decisions of the Organization of Petroleum Exporting Countries relating to export quotas and their compliance or non-compliance with such self-imposed quotas;

• weather conditions, including hurricanes, floods, and other natural disasters;

• domestic and foreign governmental regulations;

• the effect of worldwide conservation of resources;

• the price and availability of alternative fuels, including liquefied natural gas;

• political conditions in natural gas and crude oil producing regions, including terrorist activities and other hostilities;

• the proximity of reserves to, and capacity of, transportation facilities;

• the price of foreign imports of natural gas and crude oil; and

• overall global and domestic economic conditions.

     Any material decline in prices could result in a material reduction of our operating results, production revenue, reserves, and overall value. The economics of producing from some wells could change as a result of lower commodity prices. As a result, we could elect not to produce from certain wells. Any material decline in commodity prices could also result in a reduction in our natural gas and crude oil acquisition and development activities.

     Any future and sustained period of weakness in the price of natural gas or crude oil would also have an adverse effect on our borrowing capacity because borrowings under our senior secured credit facilities are limited by a borrowing base amount that is established periodically by the lenders. This borrowing base amount is determined by the lenders based on their estimate of the value of our proved reserves. A reduction in the quantity or value of certain of our reserves may also obligate us to make additional payments under our processing agreement with MPP.

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     In addition, under Canadian GAAP, natural gas and crude oil 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. A future and sustained period of low prices of natural gas or crude oil may require us to write down the carrying amount of our natural gas and crude oil 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 natural gas and crude oil reserves involve a great deal of uncertainty, because they depend in large part on 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 natural gas and crude oil exists at a particular location, and whether natural gas and crude oil are recoverable from a reservoir. The probability of the existence and recoverability of reserves is less than 100% and actual recoveries of proved reserves will differ from estimates, and the difference may be material.

     Estimates of natural gas and crude oil reserves require numerous assumptions relating to operating conditions and economic factors, including, among others:

• the price at which recovered natural gas and crude oil can be sold;

• the costs associated with recovering natural gas and crude oil;

• the prevailing environmental conditions associated with drilling and production sites;

• the availability of enhanced recovery techniques;

• the ability to market natural gas and crude oil production; and

• governmental and other regulatory factors, such as taxes, royalty rates and environmental laws.

A change in one or more of these factors could result in known quantities of natural gas and crude oil previously estimated as proved reserves becoming unrecoverable. For example, a decline in the market price of natural gas or crude oil to an amount that is less than the cost of recovery of such natural gas and crude oil 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 therefrom that are prepared by different independent engineers, or by the same engineers at different times, may vary substantially. See “Presentation of our Reserve Information.”

There are differences in U.S. and Canadian practices for reporting reserves and production.

     Our production volumes and reserve estimates are not directly comparable to those made in filings subject to SEC reporting and disclosure requirements, as we generally report production and reserve quantities in accordance with Canadian practices. These practices are different from the practices used to report production and estimate reserves in reports and other materials filed with the SEC in that the Canadian practice is to report gross production and reserve volumes, which are prior to the deduction of royalties and similar payments. In the United States, production and reserve volumes are reported after deducting these amounts.

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We might not be able to replace reserves that we have produced.

     Our future success depends on our ability to find, develop and acquire additional natural gas and crude oil reserves that are economically recoverable. Without successful exploration, development, exploitation or acquisition activities, our reserves will deplete and, as a consequence, either our production or the average reserve life of our reserves will decline. Either decline may result in a reduction in cash available to service our obligations, including the payment of interest or principal on the Notes. We cannot assure you that we will be able to find and develop or acquire additional reserves at an acceptable cost.

     We will be required to make substantial capital expenditures to develop our existing reserves, to discover new natural gas and crude oil 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 natural gas and crude oil properties in the ordinary course of our business. If these offers are accepted, our capital needs may increase substantially.

If we are unsuccessful in acquiring and developing natural gas and crude oil 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 natural gas and crude oil properties requires an assessment of:

• recoverable reserves;

• future natural gas and crude oil prices and operating costs;

• the costs of exploitation and development;

• potential environmental and other liabilities; and

• productivity of new wells drilled.

These assessments are estimates. If our estimates prove to be inaccurate, we may not recognize an acceptable return from properties we acquire or may not recover the purchase price of a property from the sale of production from the property.

Information in this short form prospectus regarding our future exploitation, development and exploration projects reflects our current intent and is subject to change.

     We describe our current exploration, development and exploitation plans in this short form prospectus. Whether we ultimately undertake an exploration, development or exploitation project will depend on a number of factors, including:

• availability and cost of capital;

• receipt of additional seismic data or the reprocessing of existing data;

• current and projected natural gas or crude oil prices;

• the costs and availability of drilling rigs, other equipment supplies and personnel necessary to conduct these operations;

• the success or failure of activities in similar areas;

• changes in the estimates of the costs to complete the projects;

• our ability to attract other industry partners to acquire a portion of the working interest in a property to reduce costs and exposure to risks; and

• decisions of our joint working interest owners.

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     We will continue to gather data about our projects and it is possible that additional information will cause us to alter our schedule or determine that a project should not be pursued at all. We may also pursue alternative or additional projects. You should understand that our plans regarding our projects may change.

We operate in a highly competitive industry in which many of our competitors have greater resources.

     The oil and gas industry is highly competitive. We compete for capital, acquisitions of reserves, undeveloped lands, skilled personnel, access to drilling rigs, service rigs and other equipment, access to processing facilities, pipeline and refining capacity and in many other respects with a substantial number of other organizations, many of which may have greater technical and financial resources than us. Some of these organizations not only explore for, develop and produce natural gas and crude oil but also carry on refining operations and market crude oil and other products on a worldwide basis. As a result of these complementary activities, some of our competitors may have greater and more diverse competitive resources to draw on than we do. Drilling rigs, service rigs, equipment and experienced crews continue to operate at or near maximum capacity in the WCSB, which has resulted in escalating drilling costs and inefficiencies. Strong demand for experienced professionals has caused a significant increase in salaries and workloads, further adding to inefficiency in the industry.

     Our ability to acquire additional properties and to discover reserves in the future depends on our ability to evaluate and select suitable properties and to complete transactions in a highly competitive and challenging environment. See “Business — Competitive Conditions”.

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, including completions and tie-ins, 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:

• adverse weather conditions;

• compliance with governmental requirements; and

• shortages or delays in the delivery of equipment and services.

Fluctuations in foreign currency exchange rates could adversely affect our business.

     The price that we receive for a majority of our natural gas and crude oil is based on United States dollar denominated benchmarks and, therefore, the price that we receive in Canadian dollars is affected by the exchange rate between the two currencies. A material increase in the value of the Canadian dollar relative to the United States dollar may negatively impact our net production revenue by decreasing the Canadian dollars we receive for a given United States dollar price.

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 risks and hazards in exploring for, producing, processing and transporting natural gas and crude oil, including:

• our drilling operations could encounter unexpected formations or pressures that could cause damage to equipment or personal injury;

• we could experience fires, explosions, blowouts, oil spills or other accidents;

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• we could experience equipment failure that curtails or stops production, processing or transportation;

• drilling, production, processing and transportation activities, such as trucking of oil, may be interrupted by bad weather or indefinitely suspended by natural disasters; and

• we could be unable to access our properties or conduct our operations due to surface conditions.

The risks and hazards of our operations could result in damage to, or destruction of, natural gas and oil wells, production and processing facilities, pipelines or other property, environmental damage or personal injury for which we will be liable. The location of some of our operations near populated areas, including residential areas, commercial business centers and industrial sites, could increase these risks and hazards. We cannot fully protect against all of these risks, nor are all of these risks insurable. We may become liable for damages arising from these events against which we cannot insure or against which we may elect not to insure because of high premium costs or other reasons. The occurrence of a significant event not fully insured or indemnified against could seriously harm our financial condition and operating results.

We will continue to pursue acquisitions and dispositions.

     We will continue to seek opportunities to generate value through business combinations, and purchases and sales of assets. We examine potential transactions on a regular basis, depending on market conditions, available opportunities and other factors. Acquisitions, particularly large acquisitions, pose various risks. Dispositions of portions of our existing business or properties would be intended to result in the realization of immediate value but would consequently result in lower cash flows over the longer term unless the proceeds are reinvested in more productive assets.

Our hedging activities could result in losses.

     The nature of our operations results in exposure to fluctuations in commodity prices. We monitor and, when our management deems it appropriate, may utilize derivative financial instruments and physical delivery contracts to hedge 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 natural gas and crude oil prices. See the sections of this short form prospectus under “Management’s Discussion and Analysis of Financial Condition and Results of Operations “ entitled, “—Results of Operations — Other Expenses – Risk Management”, and “—Additional Disclosures – Market Risk”.

     If commodity prices increase above those levels specified in our various hedging agreements, 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:

• we are unable to produce natural gas or crude oil to fulfill our obligations;

• we are required to pay a margin call on a hedge contract; or

• we are required to pay royalties based on a market or reference price that is higher than our fixed or ceiling price.

We are subject to legal limitations that may adversely affect the cost, manner or feasibility of doing business.

     We are subject to extensive laws and regulations on taxation, exploration and development, and environmental and safety matters in areas where we own or operate properties. These laws and regulations are under continuing review for amendment or expansion, and we could be forced to expend significant resources to comply with new laws or regulations or changes to existing requirements. Many laws and regulations require drilling permits and govern the spacing of wells, the prevention of waste, rates of production and other matters. These statutes and regulations, and any others that are passed by the

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jurisdictions where we have production, could limit the total number of wells drilled or the total allowable production from successful wells, which could limit our revenues. Noncompliance with these statutes and regulations could also result in substantial penalties or in the suspension or termination of our operations. In addition, if a change in any statute or regulation materially and adversely affects our ability to produce reserves, we would be in default under our processing agreement with MPP and would be obligated to pay liquidated damages. See “Description of Material Indebtedness and Other Commitments – Mazeppa Processing Partnership and Related Agreements”.

Complying with environmental and other government regulations could be costly and could negatively impact our production.

     Our operations are governed by numerous Canadian laws and regulations at the provincial and federal level regarding the operation and maintenance of natural gas and crude oil facilities, the management of hazardous materials, the discharge of wastes 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.

     We could incur liabilities that could be material or could be required to cease production on properties if environmental damage occurs. See “Business — Environmental”.

     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 fines, incurred liability and increased capital expenditures and operating costs, any of which could have a material adverse effect on our financial condition or results of operations.

     The oil and gas industry is subject to extensive environmental regulations pursuant to local, provincial and federal legislation. A breach of that legislation may result in the imposition of fines or penalties, or other sanctions, or the issuance of “clean up” orders. Legislation regulating our industry may be changed to impose higher standards and potentially more costly obligations. For example, Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases.” Our production facilities and other operations and activities emit greenhouse gases that may subject us to legislation regulating emissions of greenhouse gases. The Government of Canada has proposed a Climate Change Plan for Canada that suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including natural gas and oil development and production. Future federal legislation, together with provincial emission reduction requirements, such as those under the Climate Change and Emissions Management Act (Alberta), may require the reduction of emissions or emissions intensity of our operations and facilities. The direct or indirect costs of these regulations may adversely affect our business.

     We do not establish a separate reclamation fund for the purpose of funding our estimated future environmental and reclamation obligations. We cannot assure you that we will be able to satisfy our future environmental and reclamation obligations.

     We are not fully insured against certain environmental risks, either because such insurance is not available or because of high premium costs. In particular, insurance against risks from environmental pollution occurring over time (as opposed to sudden and catastrophic damages) is not available on economically reasonable terms. Accordingly, our properties may be subject to liability due to hazards that cannot be insured against, or that have not been insured against due to prohibitive premium costs or for other reasons.

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     Any site reclamation or abandonment costs incurred in the ordinary course in a specific period will be funded out of our cash flow. Should we be unable to fully fund the cost of remedying an environmental claim, we might by required to suspend operations or enter into interim compliance measures pending completion of the required remedy.

Factors beyond our control affect our ability to market production, and any decline in our ability to market our production could have a material adverse effect on our production levels or on the price that we receive for our production.

     Our ability to market natural gas and crude oil from our wells depends on numerous factors beyond our control. These factors include:

• the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities;

• the supply of and demand for natural gas and crude oil;

• the availability of alternative fuel sources;

• the effects of inclement weather;

• Canadian federal regulation of natural gas and crude oil sold or transported outside of the province of Alberta;

• Canadian federal and provincial, as well as U.S. federal and state, regulation of natural gas and crude oil production, processing and transportation; and

• tax and energy policies.

Because of these factors, we could be unable to market all of the natural gas or crude oil we produce. In addition, we may be unable to obtain favourable prices for the natural gas and crude oil we produce.

We do not own all of our infrastructure.

     We do not own all of our processing facilities. Third parties that own facilities through which we process our production may encounter processing or financial constraints that could reduce the amount of our production that we may process at their facilities or otherwise delay processing of our production. A majority of our southern Alberta production is processed at the Mazeppa gas plant through our processing agreement with MPP. See “Description of Material Indebtedness and Other Commitments – Mazeppa Processing Partnership and Related Agreements.” Pursuant to a management agreement, we effectively control the operations at this plant. Our processing agreement and management agreement each terminate in 2009; however, we have committed to process a majority of our production from our southern Alberta reserves at the Mazeppa gas plant through 2019. If we do not retain effective control of the Mazeppa gas plant by renewing our management and processing agreements or purchasing the plant, our risks of processing our production with third-parties (as discussed above) may be increased.

We do not control all of our operations.

     We do not operate all of our properties, so we have limited influence over the operations of some of our properties. Our lack of control could result in the following:

• the operator might initiate exploration or development on a faster or slower pace than we prefer;

• the operator might propose to drill more wells or build more facilities on a project than we have funds for or that we deem appropriate, which could mean that we are unable to participate in the project or share in the revenues generated by the project even though we paid exploration costs which contributed to the development of the project; and

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• the operator might refuse to initiate a project, and we might be unable to independently pursue the project.

Any of these events could materially reduce the value of our non-operated properties. The continuing production from a property, and to some extent the marketing of that production, is dependent on the ability of the operators of our properties. To the extent a third-party operator fails to perform its duties properly or becomes insolvent, our cash flows may be materially reduced.

Unforeseen title defects may result in a loss of entitlement to production and reserves.

     We conduct title reviews in accordance with industry practice prior to purchasing resource assets; however, these reviews do not guarantee that an unforeseen defect in the chain of title will not arise and defeat our title to the purchased assets. If this type of defect were to occur, our entitlement to the production and reserves from the purchased assets could be jeopardized and, as a result, our cash flows may be materially reduced.

If we are unable to access our properties or conduct our operations due to surface conditions, our business will be adversely affected.

     The development and exploitation of natural gas and crude oil reserves depends on access to areas where operations are to be conducted. Oil and natural gas industry operations in the WCSB 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. In addition, landowner constraints could disrupt access to our properties. Our inability to access our properties or to conduct our business as planned could result in a shutdown or slowdown of our operations.

Aboriginal peoples may make claims regarding the lands on which our operations are conducted.

     Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada, including some of the properties on which we conduct our operations. If any aboriginal peoples are successful in claiming aboriginal title or rights to the lands on which any of our properties are located, it could have a material adverse effect on our operations.

Essential equipment might not be available.

     Natural gas and crude oil exploration and development activities depend on the availability of drilling and related equipment in the particular areas where those activities will be conducted. Increased demand for that equipment or access restrictions imposed on us may affect the availability of that equipment to us and delay our exploration and development activities.

Our business may suffer if we lose key personnel.

     We depend to a large extent on the services of key management personnel, including our executive officers and other key employees, the loss of any of whom could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to any of our employees. Our success will be dependent on our ability to continue to employ and retain skilled personnel.

Risks Related to the Notes

If you do not properly tender your Initial Notes, you will not receive Exchange Notes in the Exchange Offer, and you may not be able to sell your Initial Notes.

     We intend to register the Exchange Notes, but not the Initial Notes, under the Securities Act. The Initial Notes may not be offered or sold in the United States except pursuant to an exemption from the

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registration of the Securities Act and applicable state securities laws or pursuant to an effective registration statement. The Initial Notes may not be offered or sold in Canada except pursuant to applicable prospectus registration exemptions. We will issue Exchange Notes only in exchange for Initial Notes that are timely received by the Exchange Agent, together with all required documents, including a properly completed and duly signed letter of transmittal. Therefore, you should allow sufficient time to ensure timely delivery of the Initial Notes, and you should carefully follow the instructions on how to tender your Initial Notes.

     Neither we nor the Exchange Agent is required to tell you of any defects or irregularities with respect to your tender of the Initial Notes. If you do not tender your Initial Notes or if we do not accept your Initial Notes because you did not tender your Initial Notes properly, then, after we consummate the Exchange Offer, you will continue to hold Initial Notes that are subject to the existing special interest and transfer restrictions. In general, you may not offer or sell the Initial Notes in the United States unless they are registered under the Securities Act or offered or sold in a transaction exempt from, or not subject to, the registration requirements of the Securities Act and applicable state securities laws.

     Although we may in the future seek to acquire unexchanged Initial Notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise, we have no present plans to acquire any unexchanged Initial Notes or to file with the SEC a shelf registration statement or a prospectus with any securities regulatory authority in Canada to permit resales of any unexchanged Initial Notes. In addition, holders who do not tender their Initial Notes, except for initial purchasers or holders of Initial Notes who are prohibited by applicable law or SEC policy from participating in the Exchange Offer or may not resell the Exchange Notes acquired in the Exchange Offer without delivering a prospectus and this short form prospectus is not appropriate or available for such resales by such holders, will not have any further registration rights and will not have the right to receive special interest on their Initial Notes.

The market for the Initial Notes may be significantly more limited after the Exchange Offer.

     Because we anticipate that most holders of Initial Notes will elect to exchange their Initial Notes, we expect that the liquidity of the market for any Initial Notes remaining after the completion of the Exchange Offer may be substantially limited. Any Initial Notes tendered and exchanged in the Exchange Offer will reduce the aggregate principal amount of the Initial Notes outstanding. Accordingly, the liquidity of the market for any Initial Notes could be adversely affected and you may be unable to sell them. The extent of the market for the Initial Notes and the availability of price quotations would depend on a number of factors, including the number of holders of Initial Notes remaining outstanding and the interest of securities firms in maintaining a market in the Initial Notes. An issue of securities with a smaller number of units available for trading may command a lower, and more volatile, price than would a comparable issue of securities with a larger number of units available for trading; therefore, the market price for the Initial Notes that are not exchanged may be lower and more volatile as a result of the reduction in the aggregate principal amount of the Initial Notes outstanding.

     If you do not properly tender your Initial Notes, you will not receive Exchange Notes in the Exchange Offer, and you may not be able to sell your Initial Notes.

Our indebtedness could adversely affect our financial health and prevent us from fulfilling our obligations under the Notes.

     We have now and will continue to have a significant amount of indebtedness. On September 30, 2005, we had total indebtedness of approximately $452 million, which consisted of approximately $260 million outstanding under our senior secured credit facilities and the US$165 million principal amount of our 9.90% Notes ($192 million based on the Bank of Canada noon rate on September 30, 2005 of US$1.00 = $1.1611). Following the offering of the Initial Notes on November 22, 2005, we issued US$300 million of Initial Notes and used the net proceeds therefrom to purchase the 9.90% Notes tendered in our tender offer which expired on November 29, 2005, and to repay a portion of our outstanding debt under our senior secured credit facilities. As of September 30, 2005, after giving effect to the offering of the Initial Notes, the completion of the tender

24

offer for the 9.90% Notes and the repayment of a portion of our debt under our senior secured credit facilities, we have total indebtedness of $484 million (excluding intercompany indebtedness), which consists of the principal amount of the Initial Notes and Exchange Notes, the US$6.75 million principal amount of our 9.90% Notes that were not tendered to the tender offer ($7.84 million based on the Bank of Canada noon rate on September 30, 2005 of US$1.00 = $1.1611) and $128 million outstanding under our senior secured credit facilities. See “Capitalization”. Our indebtedness could materially and adversely affect us in a number of ways. For example, it could:

• make it more difficult for us to satisfy our obligations with respect to the Notes;

• increase our vulnerability to general adverse economic and industry conditions;

• 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;

• limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• place us at a competitive disadvantage compared to our competitors that have less debt; and

• limit our ability to borrow additional funds, including for future acquisitions, to meet our operating expenses and for other purposes.

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 may be able to incur substantial additional indebtedness in the future. The terms of the indenture governing the Notes do not fully prohibit us from doing so. If new indebtedness is added to our current level of indebtedness, the related risks that we now face could intensify. See “Description of Material Indebtedness and Other Commitments”.

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 the Notes, and to fund planned capital expenditures will depend on our ability to generate cash in the future. This is subject to general economic, financial, competitive, legislative, regulatory and other factors, many of which are beyond our control.

     Our business may not generate sufficient cash flow from operations and we may not have available to us future borrowings in an amount sufficient to enable us to pay our indebtedness, including the Notes, or to fund our other liquidity needs. In these circumstances, we may need to refinance all or a portion of our indebtedness, including the Notes, on or before maturity. We may not be able to refinance any of our indebtedness, including our senior secured credit facilities and the Notes, on commercially reasonable terms or at all. Without this financing, we could be forced to sell assets to make up for any shortfall in our payment obligations under unfavourable circumstances. The terms of our senior secured credit facilities and the indenture governing the Notes limit our ability to sell assets and also restrict the use of proceeds from such a sale. Moreover, substantially all of our assets have been pledged to secure repayment of our indebtedness under our senior secured credit facilities. In addition, we may not be able to sell assets quickly enough or for sufficient amounts to enable us to meet our obligations, including our obligations under the Notes.

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The Notes and the guarantees will be effectively subordinated to our secured indebtedness and certain indebtedness of our subsidiaries.

     The Notes and the guarantees will be general unsecured obligations of the Issuer, Compton and the other guarantors, and therefore will be effectively subordinated to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness. Our senior secured credit facilities are secured by all of our and our subsidiaries’ (including the Issuer’s) assets. The indenture governing the Notes permits us to incur additional secured indebtedness provided certain conditions are met. See “Description of the Notes — Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”. 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 will not be available for satisfaction of any amounts owed under our unsecured indebtedness, including the Notes, until our obligations under our secured indebtedness are paid.

     Through a management agreement, we manage the activities of Mazeppa Processing Partnership, or MPP, and therefore we are considered to be the primary beneficiary of MPP’s operations. As a result, MPP’s assets are included in our consolidated balance sheet in accordance with the guidelines issued by the Canadian Accounting Standards Board, in Accounting Guideline 15, “Consolidation of Variable Interest Entities.” However, because we do not have an ownership position in MPP, MPP’s assets are not available to our creditors.

We may not have the ability to raise the funds necessary to finance, and may also be prohibited from making, the change of control offer required by the indenture.

     Upon the occurrence of certain specific kinds of change of control events, we will be required under the terms of the indenture governing the Notes to offer to repurchase all outstanding Notes at 101% of the principal amount thereof plus accrued and unpaid interest and additional interest, if any, to the date of repurchase. We may not have sufficient funds at the time of the change of control to make the required repurchase of Notes. A change of control would also be an event of default under our MPP processing agreement, which could result in, among other things, the termination of that agreement or an obligation to pay liquidated damages. See “Description of Material Indebtedness and Other Commitments — Mazeppa Processing Partnership and Related Agreements”. In addition, restrictions in our senior secured credit facilities will not allow repurchases of the Notes prior to their stated maturity regardless of our obligations under the indenture and a change of control may constitute an event of default under our senior secured credit facilities. In the event a change of control occurs at a time when we are prohibited from purchasing the Notes under these agreements and we are unable to get consent from our lenders to repurchase the Notes or are unable to refinance such obligations, we may be unable to repurchase the Notes. Any failure to repurchase the Notes under a change of control situation would constitute an event of default under the indenture governing the Notes which may in turn lead to an event of default under our senior secured credit facilities or agreements governing our other future indebtedness.

Federal, provincial and state statutes allow courts, under specific circumstances, to void subsidiary 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:

• incurred the debt with the intent to hinder, delay or defraud creditors;

• received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee; and

• was insolvent or rendered insolvent by reason of such incurrence; or

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• was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

• 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.

     The measure of insolvency for purposes of the aforementioned fraudulent transfer laws will vary depending on the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent under these laws if:

• the sum of its debts, which may include certain contingent liabilities, were greater than the fair saleable value of all of its assets; or

• the present, fair saleable value of its assets was less than the amount that would be required to pay its probable liabilities on its existing debts, which may include certain contingent liabilities, as they become absolute and mature, or if the guarantor is unable in the ordinary course of business to meet its obligations as they become due.

Based on historical financial information, recent operating history and other factors, we believe that each guarantor of the Notes offered hereby, upon completion of the Exchange Offer, will not be insolvent, will not have unreasonably small capital for the business in which it is engaged and will not have incurred debts beyond its ability to pay such debts as they mature. There can be no assurance, however, as to what standard a court would apply in making such determinations or that a court would agree with our conclusion in this regard.

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 short form prospectus reside principally in Canada. Because most of these persons are located outside the United States, it may not be possible for you to effect service of process within the United States on these persons. Furthermore, it may not be possible for you to enforce against us or them, in the United States, judgments obtained in United States 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 Stikeman Elliott LLP, our Canadian counsel, that there is doubt as to the enforceability, in original actions in Canadian courts, of liabilities based on the United States federal securities laws and as to the enforceability in Canadian courts of judgments of United States courts obtained in actions based on the civil liability provisions of the United States federal securities laws. Therefore, it may not be possible to enforce those actions against us, our directors and officers or some of the experts named in this short form prospectus.

If an active trading market does not develop for the Notes you may not be able to resell them.

     We cannot assure you that an active trading market will develop for the Exchange Notes. If no active trading market develops, you may not be able to resell your Exchange Notes at their fair market value or at all. Future trading prices of the Exchange Notes will depend on many factors, including, among other things, prevailing interest rates, our operating results and the market for similar securities. We have been informed by the Initial Purchasers of the Initial Notes that they currently intend to make a market in the Exchange Notes after the Exchange Offer is completed; however, the Initial Purchasers may cease their market-making at any time. We do not intend to apply for listing the Exchange Notes on any securities exchange.

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Non-U.S. holders of the Notes are subject to applicable restrictions on the resale of the Notes.

     We sold the Initial Notes in reliance on exemptions from applicable Canadian provincial and territorial securities laws and laws of other jurisdictions where the Initial Notes were offered and sold, and therefore the Initial Notes may be transferred and resold only in compliance with the laws of those jurisdictions to the extent applicable to the transaction, the transferor and the transferee. Although we intend to register the Exchange Notes under the Securities Act, we did not, and do not intend to, qualify the Exchange Notes by prospectus in Canada or any other jurisdiction, and, accordingly, the Exchange Notes will be subject to applicable restrictions on resale in Canada and in any other jurisdiction. In addition, non-U.S. holders will remain subject to restrictions imposed by the jurisdiction in which the holder is resident.

Certain persons who participate in the Exchange Offer must deliver a prospectus in connection with resales of the Exchange Notes, which subjects you to potential liability under the Securities Act.

     In some instances described in this short form prospectus under “The Exchange Offer — Resale of the Exchange Notes,” you will be obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer your Exchange Notes. In those cases, if you transfer any Exchange Notes 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.

We are subject to restrictive covenants.

     Should our “borrowing base” under our senior secured credit facilities (which is set at the discretion of our lenders and is generally based on estimates of the lending value of our proved natural gas and crude oil reserves) fall below the amounts borrowed under those credit facilities, we would be obligated to prepay outstanding obligations under those credit facilities to the extent of the shortfall. A breach of this covenant would result in an event of default under our senior secured credit facilities. Upon the occurrence of any event of default under our senior secured credit facilities, our lenders could elect to declare all amounts outstanding thereunder, together with accrued interest, to be immediately due and payable. If the lenders providing our credit facilities accelerate the payment of the indebtedness, we cannot assure you that our assets would be sufficient to repay in full that indebtedness and our other indebtedness, including the Notes.

     Under our MPP processing agreement, we are also subject to certain operating restrictions. These restrictions provide that in certain circumstances, including if our proved reserves decline below a specified quantity, or value, we would be in default under that agreement and may be required to pay a significant amount. See “Description of Material Indebtedness and Other Commitments – Mazeppa Processing Partnership and Related Agreements”. These restrictions could reduce our operational flexibility and adversely affect our ability to repay amounts due under the Notes.

     The indenture governing the Notes also imposes significant operating and financial restrictions on us. The restrictions in our senior secured credit facilities or in this indenture may adversely affect our ability to finance our future operations and capital needs and to pursue available business opportunities. Moreover, any new indebtedness we incur may impose financial restrictions and other covenants on us that may be more restrictive than the indenture governing the Notes.

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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.

     We received net proceeds of approximately US$289 million (approximately $336 million based on the Bank of Canada noon buying rate on September 30, 2005 of US$1.00=$1.1611) from the sale by private placement of our Initial Notes, after deducting the initial purchasers’ commission and offering expenses. These net proceeds were used by Compton Holdings, our wholly-owned subsidiary, to purchase the 9.90% Notes that were tendered in our tender offer which expired on November 29, 2005, and by us, to repay a portion of our outstanding debt under our senior secured credit facilities.

CAPITALIZATION

     The table below sets forth our consolidated cash and cash equivalents and our consolidated capitalization as of December 31, 2004 on an actual basis and as of September 30, 2005 on an actual basis and as adjusted to give effect to the issuance of the Initial Notes, the exchange of the Initial Notes for the Exchange Notes and the use of net proceeds from the sale of the Initial Notes to purchase those 9.90% Notes tendered to Compton Holdings and repay a portion of our outstanding debt under our senior secured credit facilities.

     You should read this table together with “Selected Historical Consolidated Financial Data” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, and our financial statements and related notes beginning on page F-1.

	As at December 31, 2004		As at September 30, 2005
	Actual		Actual		As Adjusted
	(in thousands)
Cash and cash equivalents	$	10,068	$	16,900	$	16,900
Long-term debt (including current portion):
Senior secured credit facilities(1)	$	220,000	$	260,000	$	128,258
9.90% Notes(2)(3)		198,594		191,582		7,838
Notes(2)		—		—		348,330
Total long-term debt (including current portion)	$	418,594	$	451,582	$	484,426
Shareholders’ equity(4)		424,078		557,041		557,041
Total capitalization	$	842,672	$	1,008,623	$	1,041,467

(1)	At September 30, 2005, our senior secured credit facilities provided for total borrowings of up to $274 million, including $10 million of available borrowings under our working capital facility. Our senior secured credit facilities provided for total borrowings of up to $289 million following issuance of the Initial Notes. Net proceeds from the issuance of the Initial Notes, after issuance costs of approximately $10 million, were used to purchase those 9.90% Notes tendered to Compton Holdings, our wholly-owned subsidiary, pursuant to the terms of the tender offer which expired on November 29, 2005, and to repay approximately $132 million of our outstanding debt under our senior secured credit facilities. Approximately $161 million is available for borrowing under our senior secured credit facilities. Borrowing under our extendible revolving term credit facility is limited by a borrowing base which is established periodically by the lenders.
(2)	The 9.90% Notes, Initial Notes and Exchange Notes offered by this short form prospectus have been converted to Canadian dollars based on the Bank of Canada noon buying rate on September 30, 2005, which was US$1.00 = $1.1611.
(3)	The 9.90% Notes purchased in the tender offer were not cancelled, but instead, remain outstanding and held by our wholly-owned subsidiary, Compton Holdings.
(4)	In February 2005, we issued 7,500,000 common shares for gross proceeds of $90.0 million before underwriters’ fees and issue expenses of $4.1 million.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

     The table set forth below provides our selected financial data for the twelve months ended September 30, 2005, each of the nine-month periods ended September 30, 2005 and 2004 and each of the years ended December 31, 2004, 2003 and 2002. The financial data for each of the years ended December 31, 2004, 2003 and 2002 have been derived from our audited consolidated financial statements for those years, included elsewhere in this short form prospectus, which were audited by Grant Thornton LLP, independent accountants.

     The financial data for each of the nine-month periods ended September 30, 2005 and 2004 have been derived from our unaudited consolidated financial statements for those periods, included elsewhere in this short form prospectus. The unaudited consolidated financial statements for those periods have been prepared on the same basis as our audited consolidated financial statements except as disclosed in the notes to those financial statements, included elsewhere in this short form prospectus. Our management believes that the unaudited consolidated financial statements for those periods contain all adjustments necessary for a fair presentation of the financial information presented (consisting only of normal recurring adjustments). The financial data for the interim periods is not necessarily indicative of the results that may be expected for our full year of operations.

     Our financial statements have been prepared in accordance with Canadian GAAP, which differs in some material respects from U.S. GAAP. For a discussion of the principal differences between U.S. GAAP and Canadian GAAP, you should read Note 19 to our consolidated financial statements included elsewhere in this short form prospectus. Although we do not own the equity of MPP, through a management agreement we manage the activities of MPP and are considered to be the primary beneficiary of MPP’s operations. As a result, our consolidated financial statements include the assets, liabilities and operations of MPP. See Note 4 to our consolidated financial statements.

     This selected financial data should be read along with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and the related notes included elsewhere in this short form prospectus.

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	Twelve
	Months
	Ended			Nine Months Ended
	September 30,			September 30,						Year Ended December 31,
	2005(1)			2005			2004			2004			2003			2002
				(in thousands of Canadian dollars, except ratios)
Canadian GAAP
Statement of Earnings Data:
Revenue:
Natural gas and oil revenues	$	474,640		$	373,451		$	290,470		$	391,659		$	346,565		$	226,597
Royalties		(114,680	)		(89,193	)		(67,929	)		(93,416	)		(82,566	)		(47,497	)
Net revenue		359,960			284,258			222,541			298,243			263,999			179,100
Expenses:
Operating		63,564			47,873			39,964			55,655			49,916			45,546
Transportation		10,276			7,740			6,059			8,595			8,447			8,167
General and administrative		19,239			14,359			10,335			15,215			12,206			9,845
Interest and finance charges		33,018			24,210			24,925			33,733			30,595			23,197
Depletion and depreciation		98,807			74,499			58,246			82,554			61,749			55,473
Foreign exchange (gain) loss		(16,965	)		(7,006	)		(4,672	)		(14,631	)		(47,368	)		1,583
Accretion of asset retirement obligations		1,825			1,416			1,261			1,670			1,436			1,241
Stock-based compensation		4,965			4,254			2,699			3,410			793			190
Risk management (gain) loss		34,331			36,110			10,587			8,808			4,132			(4,424	)
Total expenses		249,060			203,455			149,404			195,009			121,906			140,818
Earnings before income taxes and non-controlling interest		110,900			80,803			73,137			103,234			142,093			38,282
Income taxes		44,238			32,530			24,475			36,183			23,323			19,970
Earnings before non-controlling interest		66,662			48,273			48,662			67,051			118,770			18,312
Non-controlling interest		7,065			5,053			1,406			3,418			(110	)		—
Net Earnings	$	59,597		$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Cash Flow Data:
Cash provided (used) by:
Operating activities(2)	$	216,944		$	185,104		$	132,697		$	164,537		$	156,211		$	90,906
Investing activities		(363,281	)		(300,336	)		(218,251	)		(281,196	)		(276,831	)		(154,138	)
Financing activities(2)		149,520			122,064			83,723			111,179			121,443			72,905
Other Financial Data:
Adjusted EBITDA(3)(4)	$	251,861		$	204,176		$	157,336		$	205,021		$	186,802		$	118,535
Ratio of Adjusted EBITDA to interest expense(5)		8.2	x		9.1	x					6.6	x		6.6	x		5.6	x
Ratio of earnings to fixed charges(6)		4.1	x		4.1	x					4.0	x		5.6	x		2.7	x
Pro forma interest expense(7)	$	35,218
Ratio of Adjusted EBITDA to pro forma interest expense(8)		7.7	x
Balance Sheet Data (at period end):
Total assets(9)	��			$	1,607,141		$	1,252,430		$	1,330,611		$	1,064,320
Long-term debt(10)					451,582			392,543			418,594			377,746
Shareholders’ equity					557,041			408,909			424,078			356,906
U.S. GAAP
Net earnings	$	60,533		$	43,978		$	49,314		$	65,869		$	98,031		$	22,055
Adjusted EBITDA(3)(4)		251,861			204,176			157,336			205,021			182,121			118,704
Ratio of Adjusted EBITDA to interest expense(5)		8.2	x		9.1	x					6.6	x		6.4	x		5.6	x
Ratio of earnings to fixed charges(6)		4.2	x		4.2	x					4.1	x		4.7	x		3.1	x
Pro forma interest expense(7)	$	35,218
Ratio of Adjusted EBITDA to pro forma interest expense(8)		7.7	x

(1) The financial data for the twelve months ended September 30, 2005 is derived from our audited consolidated financial statements for the year ended December 31, 2004 and our unaudited consolidated financial statements for the nine months ended September 30, 2005 and 2004.

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(2)	Cash provided (used) by operating activities includes cash provided by MPP, to which we are not entitled because we do not have an ownership interest in MPP. Cash provided (used) by financing activities includes cash used for distributions to the general partner of MPP. See Note 4 to our consolidated financial statements included elsewhere in this short form prospectus and “Description of Material Indebtedness and Other Commitments — Mazeppa Processing Partnership and Related Agreements”.
(3)	Adjusted EBITDA is calculated as net earnings before interest and finance charges, depletion and depreciation, unrealized foreign exchange gains and losses, stock-based compensation, unrealized risk management gains and losses and income taxes and less “MPP related adjustments”, which represents depletion and depreciation and income taxes attributable to MPP. Adjusted EBITDA is not a measure of operating performance or liquidity under Canadian or U.S. GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets. We have included information concerning Adjusted EBITDA because we consider it an important supplemental measure of our performance. However, viewing Adjusted EBITDA as an indicator of our operating performance should be done with caution. Adjusted EBITDA should not be considered in isolation of, or more meaningful than, net earnings or cash provided by operating activities as determined in accordance with Canadian or U.S. GAAP. Adjusted EBITDA is not necessarily comparable to a similarly titled measure of another company.
(4)	The following table reconciles net earnings to Adjusted EBITDA:

	Twelve
	Months
	Ended			Nine Months Ended
	September 30,			September 30,						Year Ended December 31,
	2005			2005			2004			2004			2003			2002
				(in thousands of Canadian dollars)
Canadian GAAP
Net Earnings:	$	59,597		$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Add (deduct)
Interest and finance charges		33,018			24,210			24,925			33,733			30,595			23,197
Depletion and depreciation		98,807			74,499			58,246			82,554			61,749			55,473
Unrealized foreign exchange (gain) loss		(16,961	)		(7,012	)		(4,703	)		(14,652	)		(47,388	)		1,583
Stock-based compensation		4,965			4,254			2,699			3,410			760			—
Unrealized risk management (gain) loss		31,025			34,930			6,084			2,179			—			—
Income taxes		44,238			32,530			24,475			36,183			23,323			19,970
MPP related adjustments		(2,828	)		(2,455	)		(1,646	)		(2,019	)		(1,117	)		—
Adjusted EBITDA	$	251,861		$	204,176		$	157,336		$	205,021		$	186,802		$	118,535
U.S. GAAP
Net Earnings:	$	60,533		$	43,978		$	49,314		$	65,869		$	98,031		$	22,055
Add (deduct)
Interest and finance charges		33,018			24,210			24,925			33,733			30,595			23,197
Depletion and depreciation		98,807			74,499			58,246			82,554			61,749			54,931
Unrealized foreign exchange (gain) loss		(16,961	)		(7,012	)		(4,703	)		(14,652	)		(47,388	)		1,583
Stock-based compensation		4,965			4,254			2,699			3,410			760			—
Unrealized risk management (gain) loss		28,884			33,699			3,351			(1,464	)		24,296			(8,659	)
Income taxes		45,443			33,003			25,150			37,590			14,195			25,597
MPP related adjustments		(2,828	)		(2,455	)		(1,646	)		(2,019	)		(1,117	)		—
Adjusted EBITDA	$	251,861		$	204,176		$	157,336		$	205,021		$	181,121		$	118,704

(5)	For purposes of computing the ratio of Adjusted EBITDA to interest expense, interest expense excludes the amortization of debt issuance costs.
(6)	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 issue costs.
(7)	Pro forma interest expense gives effect to the transactions as described under “Use of Proceeds” assuming the transactions closed on September 30, 2004 and using an interest rate on the Notes of 75/8% and an average Canadian / U.S. exchange rate for the period of US$1.00 = $1.2231.

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(8)	For purposes of computing the ratio of Adjusted EBITDA to pro forma interest expense, pro forma interest expense excludes the amortization of debt issuance costs.
(9)	Total assets include the assets of MPP, in which we do not have an ownership interest.
(10)	Long-term debt includes current portion of long-term debt.

     Our interest requirements, after giving effect to the issue of the Notes, amounted to $36,798 for the 12 months ended December 31, 2004. Our earnings before interest and income tax for the 12 months then ended was $133,549, which is 3.6 times our interest requirements for this period.

     Our interest requirements, after giving effect to the issue of the Notes, amounted to $35,218 for the 12 months ended September 30, 2005. Our earnings before interest and income tax for the 12 months then ended was $136,853, which is 3.9 times our interest requirements for this period.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     This Management’s Discussion and Analysis (“MD&A”) is intended to provide both an historical and prospective view of our activities. You should read the following discussion and analysis along with our audited and unaudited financial statements and the related notes on page F-1. This MD&A may contain certain forward-looking statements under the meaning of applicable securities laws. Forward-looking statements include estimates, plans, expectations, opinions, forecasts, projections, guidance or other statements that are not statements of fact. There are many factors that could cause forward-looking statements not to be correct. See “Forward-Looking Statements.”

     Our financial statements have been prepared in accordance with Canadian GAAP. Canadian GAAP may differ in some significant respects from U.S. GAAP and thus our financial statements may not be comparable to the financial statements of U.S. companies. The principal differences as they apply to us are summarized in Note 19 to our consolidated financial statements beginning on page F-1. All amounts are stated in Canadian dollars unless otherwise specified.

     Included in this MD&A are references to terms used in the oil and gas industry, such as “adjusted net earnings from operations”, that are not defined by Canadian GAAP. Consequently these terms are non-GAAP measures. Reported amounts under these measures may not be comparable to similarly titled measures reported by other companies. Adjusted net earnings from operations should not be considered an alternative to, or more meaningful than, net earnings as determined in accordance with Canadian GAAP. We use adjusted net earnings from operations to facilitate comparability of earnings between periods. See “Presentation of Financial Information.”

Overview

     We are an Alberta-based independent public company actively engaged in the exploration, development and production of natural gas, crude oil and natural gas liquids in the WCSB. Our activities are concentrated in three core areas. As of September 30, 2005, we held working interests in 2,501 gross (1,350 net) wells, and as of December 31, 2004, we held working interests in 1,019,854 gross (729,429 net) acres of undeveloped land. As of December 31, 2004, we had established total proved reserves of 97,099 mboe gross (78,767 mboe net) with a PV-10 value of approximately $1 billion. Of these reserves, approximately 76% were natural gas reserves and approximately 87% were proved developed reserves. As of December 31, 2004, we operated approximately 88% of our proved reserves. Our growth and reserves base have resulted from exploration and development activities, complemented by strategic acquisitions.

Factors Affecting Results of Operations and Financial Condition

     Our results of operations are primarily affected by:

• our realized prices for our oil and natural gas production,

• the quantities of oil and natural gas that we produce, and

• the costs we incur in connection with our production, acquisition and development activities.

     Pricing

     Of the three principal factors affecting our results of operations and financial condition, the volatility of commodity prices, particularly natural gas prices, has had the most significant impact on our financial performance. We generally sell our production at rates that are related to current market prices. We attempt to lessen the impact of changing commodity prices to some extent by hedging a portion of our production. See “-Market Risk”.

     Production

     Our production levels are principally determined by the number of our wells and the quantity of our reserves. The quantities of natural gas, crude oil and natural gas liquids that we produce from existing wells

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tend to decrease over time due to natural reservoir depletion. We seek to offset these production declines through development of existing properties and acquisition of new properties. We have identified numerous development opportunities within our existing properties and pursue these opportunities in accordance with our capital budget. We also continually evaluate oil and gas reserve acquisition opportunities, although the quantity, quality and price of available acquisition opportunities vary over time.

     Historically, the majority of our production has been natural gas, with crude oil and natural gas liquids comprising a smaller portion of our total production. While the demand for natural gas continues to increase, conventional production in the WCSB may be peaking and new natural gas wells in the WCSB have, on average, experienced lower initial production rates. We believe developing unconventional sources of natural gas is necessary to offset overall declines and provide production growth necessary to meet anticipated increased demand. Unconventional sources include tight gas, coal bed methane, or CBM and shale gas. We expect that tight gas will be the largest unconventional form of natural gas production in the WCSB in the future. Our competitors in the Canadian oil and gas industry are also aggressively pursuing CBM. The majority of our landholdings in southern Alberta are prospective for CBM. These new unconventional resource plays require a large upfront land base, technical expertise and drilling experience.

     We have experienced abnormally wet weather conditions in southern Alberta in 2005. These wet weather conditions have interrupted and delayed well completions, pipeline construction and tie-ins. These delays have, in turn, impacted production growth. We are working to bring approximately 6,000 boe/d of behind pipe production on-line as quickly as possible. Despite these wet weather conditions, we completed our 390 well drilling program this year.

     Operating, FD&A and Other Costs

     Drilling rigs, service rigs, equipment and experienced crews continue to operate at or near maximum capacity in the WCSB, which has resulted in escalating drilling costs and inefficiencies. Strong demand for experienced professionals has caused a significant increase in salaries and workloads, further adding to operating costs and inefficiency in the industry.

     Finding development and acquisition costs, or “FD&A costs”, are the costs of adding reserves including reserve revisions, costs of acquiring undeveloped land, seismic data, drilling equipment, tie-in and field facilities as well as acquisition costs related to reserves purchased. See “—Finding, Development and Acquisition Costs.” Land prices have continued to escalate in the WCSB, adding considerably to FD&A costs.

     Additionally, the increasingly complex and ever changing government rules in Canada regarding license applications and environmental and governance matters is adding significantly to overall costs, workloads and timing of operations. The end result is that while commodity prices are strong, the cost, effort and time involved in doing business has also risen dramatically in the last several years.

     Consolidation of Mazeppa Processing Partnership

     We process the majority of our production from our Southern Alberta reserves through the facilities of Mazeppa Processing Partnership, or MPP. We do not have an ownership position in MPP. On August 18, 2004, we entered into a series of agreements whereby a third party (the “MPP Limited Partner”), subscribed for the limited partnership interests of MPP. A third party affiliated with the MPP Limited Partner acquired from us the shares of MPP Ltd., the general partner of MPP. Although we do not own the equity of MPP, through a management agreement, we manage the activities of MPP and are considered to be the primary beneficiary of MPP’s operations. As a result, our consolidated financial statements include the assets, liabilities and operations of MPP. See Note 4 to our consolidated financial statements.

     Commencing August 1, 2004, pursuant to the terms of our processing agreement with MPP, we pay a monthly fee to MPP for the transportation and processing of natural gas through the MPP owned facilities. The fee is comprised of a fixed base fee of $764,000 per month plus MPP’s operating costs, net of third party

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revenues. These amounts are eliminated from our revenues and expenses on consolidation. As a result, what would otherwise be our processing costs are eliminated and replaced by the actual operating costs of MPP. Non-controlling interest shown on our consolidated statement of earnings represents the net earnings of MPP. See “Description of Material Indebtedness and Other Commitments — Mazeppa Processing Partnership and Related Agreements” and Note 4 to our consolidated financial statements.

     MPP has guaranteed payment of certain obligations of the MPP Limited Partner to the MPP Limited Partner’s lenders. This guarantee is limited to amounts due and payable to MPP by us pursuant to the processing agreement. Our consolidated financial statements do not include the assets, liabilities and operations of the MPP Limited Partner.

     Results of Operations

     Historically, the majority of our production has been natural gas, with crude oil and natural gas liquids comprising a smaller portion of our total production. The following table sets forth production, price information and revenue before royalties relating to our operations for the periods indicated:

	Nine Months Ended
	September 30,				Years Ended December 31,
	2005		2004		2004		2003		2002
			(in thousands, except where noted)
Average production
Natural gas (mmcf/d)		130		122		123		118		112
Crude oil & natural gas liquids (bbls/d)		7,231		6,117		6,330		5,924		6,503
Total (boe/d)		28,879		26,430		26,876		25,552		25,137
Benchmark prices
NYMEX (US$/mmbtu)	$	7.12	$	5.82	$	6.09	$	5.44	$	3.25
AECO ($/mcf)	$	7.03	$	6.01	$	6.44	$	6.35	$	3.85
WTI (US$/bbl)	$	55.40	$	39.11	$	40.41	$	31.04	$	26.09
Edmonton par ($/bbl)	$	67.91	$	51.65	$	52.37	$	43.14	$	39.94
Realized prices(1)
Natural gas ($/mcf)	$	7.46	$	6.52	$	6.46	$	6.27	$	3.80
Crude oil & natural gas liquids ($/bbl)	$	55.24	$	43.33	$	43.21	$	35.59	$	30.06
Average ($/boe)	$	47.37	$	40.11	$	39.82	$	37.16	$	24.70
Revenue(1)
Natural gas	$	264,412	$	217,844	$	291,565	$	269,622	$	155,234
Crude oil and natural gas liquids		109,039		72,626		100,094		76,943		71,363
Total revenue	$	373,451	$	290,470	$	391,659	$	346,565	$	226,597

(1) Excludes the impact of hedging transactions. 2003 and 2002 amounts have been reclassified to exclude realized hedge losses and transportation charges. Prior to 2004, transportation costs were partially recorded as a reduction of revenue and partially recorded as an increase in operating expense.

     Production

     Production for the nine months ended September 30, 2005 was limited, but still increased 9% from the corresponding period in 2004 due to our ongoing accelerated exploration and development program. Additionally, as a result of a third party-operated pipeline break in central Alberta, production volumes at Thornbury were reduced by 500 boe/d for approximately 34 days in the second quarter of 2005.

     Average production in 2004 of 26,876 boe/d increased 5% from 2003 as a result of our accelerated drilling program and the resolution of facility and pipeline bottlenecks in southern Alberta. Production growth in southern Alberta, which accounts for approximately 60% of our total production volumes, was constrained by insufficient compression, pipeline and processing capacity in the first half of 2004. The expansion of the Mazeppa gas plant was completed on June 1, 2004, resulting in the elimination of these constraints.

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     Average production of 25,552 boe/d in 2003 was only marginally greater than that achieved in 2002, partially as a result of the processing and pipeline constraints noted above and the effect of scheduled plant turnarounds.

     Production growth since 2002 has been impacted by the nature of the unconventional reserves we have developed. Such reserves typically experience high decline rates in production in the initial two to three years of production, followed by decline rates of 10% or less thereafter.

     Pricing

     Commodity prices have strengthened considerably from 2002 through the first nine months of 2005, which is reflected in our realized prices. Average realized prices, on a boe basis, have increased 92% from $24.70 per boe in 2002 to $47.37 per boe in the first nine months of 2005. During this period, the AECO Benchmark natural gas price increased 83% and the Edmonton par crude oil price increased 70%.

     Our crude oil sales are priced based on Edmonton postings and are typically sold on 30-day evergreen arrangements. Natural gas liquids are bid out on an annual basis to obtain the most favorable differentials to Edmonton postings pricing. 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. In accordance with our policy, hedging programs will not exceed 50% of non-contracted production. Commodity hedge gains and losses are reflected in “Risk Management” on our consolidated income statements. See “—Other Expenses-Risk Management”.

     Revenue

     Revenue for the nine months ended September 30, 2005 increased 29% from the corresponding period in 2004 and revenue for 2004 increased 13% over 2003 as a result of increased production and higher realized commodity prices. The 53% increase in 2003 revenue over 2002 resulted primarily from higher realized commodity prices.

     Royalties

     Crown royalties are payable to the provincial government on production from Crown lands in Alberta. The Alberta Crown royalty structure is based on commodity prices and well productivity, with higher prices and higher productivity wells attracting higher royalty rates. Royalties payable on production from lands other than Crown lands are determined by negotiations between the freehold mineral owner and the lessee, and production from such lands is also subject to certain provincial taxes and royalties. The following table sets out a summary of the royalties paid by us in the periods indicated:

	Nine Months Ended
	September 30,						Years Ended December 31,
	2005			2004			2004			2003			2002
	(in thousands, except percentages)
Crown royalties	$	72,813		$	54,535		$	75,859		$	68,360		$	38,902
Other royalties		16,692			13,769			17,939			14,706			9,095
Total royalties		89,505			68,304			93,798			83,066			47,997
Alberta royalty tax credit		(312	)		(375	)		(382	)		(500	)		(500	)
Net royalties	$	89,193		$	67,929		$	93,416		$	82,566		$	47,497
Percentage of revenues		23.9	%		23.4	%		23.9	%		23.8	%		21.0	%

     Royalties, as a percentage of revenue, have remained relatively constant from 2003 through the first nine months of 2005. Royalties as a percentage of revenue increased from 21.0% in 2002 to 23.8% in 2003 largely as a result of higher commodity prices.

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     Expenses

     The following table sets forth a summary of the major expenses we incurred in the periods indicated:

	Nine Months Ended
	September 30,						Years Ended December 31,
	2005			2004			2004			2003			2002
	(in thousands, except where noted)
Operating expenses(1)	$	47,873		$	39,964		$	55,655		$	49,916		$	45,546
Operating expenses per boe ($/boe)	$	6.07		$	5.52		$	5.66		$	5.35		$	4.96
Transportation costs	$	7,740		$	6,059		$	8,595		$	8,447		$	8,167
Transportation costs per boe ($/boe)	$	0.98		$	0.84		$	0.87		$	0.91		$	0.89
General and administrative expenses	$	21,250		$	17,620		$	24,663		$	20,355		$	16,145
Capitalized general and administrative expenses		(2,449	)		(1,715	)		(2,683	)		(3,321	)		(2,689	)
Operator recoveries		(4,442	)		(5,570	)		(6,765	)		(4,828	)		(3,611	)
Total general and administrative expenses	$	14,359		$	10,335		$	15,215		$	12,206		$	9,845
General and administrative expenses per boe ($/boe)	$	1.82		$	1.43		$	1.55		$	1.31		$	1.07
Interest on bank debt	$	7,159		$	6,959		$	9,662		$	6,611		$	5,339
Interest on 9.90% Notes		15,318			15,807			21,281			21,711			15,932
Finance charges		1,733			2,159			2,790			2,273			1,926
Total interest and finance charges	$	24,210		$	24,925		$	33,733		$	30,595		$	23,197
Interest and finance charges per boe ($/boe)	$	3.07		$	3.45		$	3.43		$	3.28		$	2.53

(1) 2003 and 2002 amounts have been reclassified to exclude transportation charges.

     Operating Expenses

     Operating costs per boe increased 5.8% in 2004 over 2003 and 7.9% in 2003 over 2002. This year-over-year increase in operating costs has continued into 2005 and is due primarily to an overall rise in industry costs and the addition of field staff required for our expanding operations. Strengthening commodity prices have led to accelerated activity throughout the oil and natural gas industry, increasing the demand for and cost of goods and services.

     Transportation

     We incur charges on the transportation of our production from the wellhead to the point of sale. Pipeline tariffs and trucking rates are primarily dependent upon production location and distance from the sales point. Government regulated pipeline tolls dictate transportation rates for natural gas in Alberta. Our transportation costs on a boe basis have remained relatively constant from 2002 through 2004. Higher transportation costs in the first nine months of 2005 are associated with trucking costs due to increased crude oil production.

     Effective for 2004, our transportation costs are disclosed separately in our consolidated statements of earnings. Previously, transportation was partially recorded as a reduction of revenue and partially recorded as an increase in operating expenses. For comparative purposes, 2003 and 2002 amounts have been reclassified.

     General and Administrative Expenses

     General and administrative expenses have continued to increase from 2002 through the first nine months of 2005. This increase reflects our expanded activities and the overall increased cost of doing business in the current environment. The major components in the year-over-year increases have been additional employee costs associated with increased personnel levels and a general increase in salaries necessary to attract

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and maintain qualified personnel in a very competitive industry. Additionally, costs resulting from the current regulatory environment, including the U.S. Sarbanes-Oxley Act of 2002 and related requirements, impacted the first nine months of 2005 G&A expenses as compared to the first nine months of 2004.

     Interest Expense

     Generally, interest on bank debt has increased period-over-period consistent with our level of borrowing, partially offset by lower interest rates. Interest on our 9.90% Notes has fluctuated with changes in the Canadian/U.S. dollar exchange rate. Average debt outstanding rose in 2003 as we increased the amount drawn on our senior secured credit facilities to fund our acquisition of MPP and expansion of the Mazeppa and Gladys gas plants and related infrastructure.

     Netbacks

     Netbacks are measures used to present the results of our operations per boe of production and are presented on a field and cash flow basis. The field netback is calculated as gross revenue less royalties, operating and transportation costs. The cash flow netback is the operating netback less G&A expenses, interest and taxes. The following table presents our netbacks for the periods indicated:

	Years Ended December 31,
	2004			2003(1)			2002
	($/boe)			($/boe)			($/boe)
Realized Price(2)	$	39.82		$	37.16		$	24.70
Royalties, net		(9.50	)		(8.85	)		(5.18	)
Operating expenses(3)		(5.66	)		(5.35	)		(4.96	)
Transportation		(0.87	)		(0.91	)		(0.89	)
Field operating netback	$	23.79		$	22.05		$	13.67
General and administrative(4)		(1.55	)		(1.31	)		(1.07	)
Interest		(3.43	)		(3.28	)		(2.53	)
Current taxes		(0.28	)		(0.35	)		(0.16	)
Cash flow netback	$	18.53		$	17.11		$	9.91

(1)	2003 Operating, G&A and interest expenses have been restated to include the impact of the consolidation of MPP. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Consolidation of Mazeppa Processing Partnership”.
(2)	Excludes the impact on hedging transactions. 2003 and 2002 amounts have been reclassified to exclude realized hedge gains and losses and transportation charges.
(3)	Prior to 2004, transportation costs were partially recorded as a reduction of revenue and partially recorded as an increase in operating expense. 2003 and 2002 amounts have been reclassified to exclude transportation costs.
(4)	Excludes stock-based compensation.

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Other Expenses

     Depletion and Depreciation

     The following table summarizes our depletion and depreciation for the periods indicated:

	Nine Months Ended September 30,				Years Ended December 31,
	2005		2004		2004		2003		2002
	(in thousands, except where noted)
Total depletion and depreciation	$	74,499	$	58,246	$	82,554	$	61,749	$	55,473
Depletion and depreciation per boe ($/boe)	$	9.45	$	8.04	$	8.39	$	6.62	$	6.05

     Depletion and depreciation rates increased in 2004 and the first nine months of 2005 as the result of higher capital expenditures incurred for the exploration of reserves and optimization of proved developed reserves and are reflective of the overall increase in FD&A costs.

     Stock-based compensation

     We have a stock option plan for directors, officers and employees. The plan is designed to attract, motivate and retain outstanding individuals and to align their success with that of our shareholders. Commencing in 2003, we prospectively adopted the amended Canadian accounting standard requiring companies to use the fair value method of accounting for stock-based compensation. Under these standards, the fair value of options granted is estimated on the date of grant using the Black-Scholes option pricing model and the associated compensation expense is recognized over the vesting period. The following schedule summarizes options granted and the expense recognized:

	Nine Months Ended
	September 30				Years Ended December 31,
	2005		2004		2004		2003		2002(1)
	(in thousands, except where noted)
Options granted		2,769		2,321		2,549		1,503		1,670
Weighted average fair value of options granted ($/share)	$	5.39	$	3.57	$	3.70	$	3.01	$	3.00
Stock-based compensation expense	$	4,254	$	2,699	$	3,410	$	760	$	—

(1) Stock-based compensation expense pursuant to the fair value method of accounting was not required to be recorded in 2002 under Canadian GAAP at the time.

     Income Taxes

     Current income taxes include federal capital tax. This tax is non-deductible and is calculated on capital employed. The capital tax rate was 0.225% in 2002 and 2003 and reduced to 0.200% in 2004 and 0.175% in 2005 in connection with the planned elimination of this tax by 2008.

     Our future income taxes were $33 million in 2004, compared to $20 million in 2003 and $19 million in 2002. Future taxes in 2003 benefited from a $37 million recovery due to statutory rate reductions, and future taxes in 2004 benefited from an $8 million recovery due to such reductions. The schedule set forth below presents the combined federal and provincial statutory tax rates in Canada for 2002 through 2005 as compared to our effective future tax rate. A reconciliation of our effective tax rate to the statutory rate may be found in Note 14(a) to our consolidated financial statements included elsewhere in this short form prospectus.

     Corporate Tax Rates

	Nine Months Ended
	September 30,						Years Ended December 31,
	2005			2004			2004			2003			2002
Statutory rate		37.6	%		38.6	%		38.6	%		40.6	%		42.1	%
Effective rate		40.3	%		33.5	%		35.0	%		16.4	%		52.2	%

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     Tax Pools

     The following table summarizes our estimated tax pool balances by classification:

	As At January 1, 2005
			Maximum Annual
	Available Balance		Deduction
	(in thousands)
Canadian Exploration Expense	$	35,585		100	%
Canadian Development Expense		159,127		30	%
Canadian Oil and Gas Property Expense		182,399		10	%
Undepreciated Capital Cost		129,047		4%-100	%
Total	$	506,158

     A significant portion of our taxable income is generated by Compton Petroleum, our wholly-owned partnership. Income taxes are incurred on the partnership’s earnings in the year following their inclusion in our consolidated net earnings.

     Consolidated earnings before income taxes in 2004 include $178 million (2003 — $166 million) of partnership earnings that will be included in the following year’s income for income tax purposes. Future income taxes in 2004 include $67 million (2003 — $63 million) as a result of this deferral of partnership earnings.

     Risk Management

     Our financial results are impacted by external market risks associated with fluctuations in commodity prices, interest rates and the Canadian/U.S. dollar exchange rate. We utilize various financial instruments for non-trading purposes to manage and partially mitigate our exposure to these risks in order to protect cash flow for our capital expenditure program.

     We enter numerous commodity price contracts to manage risk associated with price volatility. In addition, concurrent with the closing of the offering of the 9.90% Notes in May of 2002, we negotiated a cross currency-interest rate swap. The swap, which converted fixed rate U.S. dollar interest obligations into floating rate Canadian dollar interest obligations, was entered into to fix the exchange rate on interest payments and to take advantage of lower floating interest rates.

     On January 1, 2004, we adopted the Canadian Institute of Chartered Accountants’ (“CICA’s”) Accounting Guideline 13, “Hedging Relationships” and the CICA’s Emergency Issues Committee (“EIC”) EIC 128, “Accounting for Trading Speculative or Non-Hedging Derivative Financial Instruments”. Financial instruments that are not designated or do not qualify as hedges under this Guideline are recorded at fair value on our consolidated balance sheet with subsequent changes recognized in consolidated net earnings. Fair value is determined on a mark-to-market basis utilizing quoted market prices. Under EIC 128, unrealized gains or losses relating to contracts in effect at the end of a period are recognized and included in risk management activity together with realized gains and losses. We elected to follow EIC 128 accounting and not designate any financial instruments as hedges.

     Adoption of EIC 128 resulted in the following:

	Nine Months Ended
	September 30,						Years Ended December 31,
	2005			2004			2004			2003			2002
	(in thousands)
Commodity contracts
Realized (gain) loss	$	1,803		$	6,208		$	9,151		$	5,497		$	(1,357	)
Unrealized (gain) loss		32,858			4,174			(1,985	)		—			—
Cross currency interest rate swap
Realized (gain)		(623	)		(1,705	)		(2,522	)		(1,365	)		(3,067	)
Unrealized (gain) loss		2,072			1,910			4,164			—			—
Total risk management (gain) loss	$	36,110		$	10,587		$	8,808		$	4,132		$	(4,424	)

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     Adjusted Net Earnings from Operations

     Net earnings are affected by a number of items of a non-operational nature. Volatility relating to these items can have a significant impact on net earnings as reported under Canadian GAAP. To assist in the comparability of earnings between periods, we calculate adjusted net earnings from operations, which eliminates the after tax effect of these items.

     The following reconciliation presents the after tax effects of items of a non-operational nature that are included in our financial results.

	Nine Months Ended September 30,						Years Ended December 31,
	2005			2004			2004			2003			2002
	(in thousands)
Net earnings, as reported	$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Non-operational items, after tax
Unrealized foreign exchange (gain) loss		(5,693	)		(3,763	)		(11,821	)		(37,761	)		1,249
Unrealized risk management (gain) loss		21,796			3,736			1,338			—			—
Stock-based compensation		2,654			1,657			2,094			451			—
Effect of tax rate changes on future income tax liabilities		(1,908	)		(8,359	)		(8,359	)		(37,130	)		(1,340	)
Adjusted net earnings from operations	$	60,069		$	40,527		$	46,885		$	44,440		$	18,221

     Capital Expenditures

     Our capital expenditures have increased year-over-year in direct relation to our increased exploration and development activities. From 2002 through the first nine months of 2005, we have continued to invest in land and production facilities together with exploratory and development drilling.

     Capital expenditures, before acquisitions and MPP-related expenditures, increased 34% from $210 million in 2003 to $282 million in 2004. This increase was primarily the result of an increase in drilling and completions expenditures, which rose from 2003 due to an increase in net wells drilled. We drilled 186 gross (146 net) wells in 2004 compared to 169 gross (137 net) wells in 2003. Drilling in 2004 included additional wells at Hooker and Callum, which are more costly than typical WCSB wells due to their depth. Facilities expenditures also increased in 2004 and included an expansion of the Niton gas plant from 10 mmcf/d to 20 mmcf/d, the installation of a 10 mmcf/d booster compressor at Niton, expansion of pipelines and a battery in the Worsley area, installation of compression plus a six inch pipeline from Brant to the Shouldice gas plant and de-bottlenecking and expansion of the Hooker pipeline system. Our total capital expenditures in 2004 were $316 million, including two corporate acquisitions that totalled $21 million and expanded our presence in our core areas and $11 million of expenditures related to the expansion of the Mazeppa gas plant facilities.

     Our capital expenditures in 2003, before acquisitions and MPP-related expenditures increased 67% from $126 million in 2002 to $210 million in 2003 primarily as a result of our increased 2003 drilling program. In 2003 we drilled 168 gross (134 net) wells, more than double the 87 gross (64 net) wells drilled by us in 2002. Total capital expenditures in 2003 were $286 million, an increase of 84% over total expenditures of $155 million in 2002, and included $65 million of MPP-related expenditures.

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     A summary of our capital expenditures for 2002 through the first nine months of 2005 is presented below:

	Nine Months Ended September 30,								Years Ended December 31,
	2005				2004				2004				2003				2002
			%				%				%				%				%
	(dollars in thousands)
Drilling and completions	$	211,739		62	$	114,782		53	$	175,003		57	$	126,308		57	$	75,369		48
Land and seismic data		45,273		13		28,078		13		38,326		12		37,128		17		29,096		19
Facilities		65,809		20		51,707		24		68,861		23		46,068		21		21,714		14
Sub-total	$	322,821		95	$	194,567		90	$	282,190		92	$	209,504		95	$	126,179		81
Property acquisitions, net		17,199		5		5,078		3		1,938		1		11,224		5		28,929		19
Corporate acquisitions		—		—		15,324		7		20,887		7		—		—		—		—
Sub-total	$	340,020		100	$	214,969		100	$	305,015		100	$	220,728		100	$	155,108		100
MPP		598				11,218				11,386				64,755				—
Total capital expenditures	$	340,618			$	226,187			$	316,401			$	285,483			$	155,108

     High commodity prices have caused many of our competitors to accelerate exploration and development programs throughout the oil and natural gas industry, raising the demand and prices for drilling rigs, completion services and supplies. We have undertaken initiatives such as bulk pipe purchases and streamlining well completions to mitigate rising costs.

Finding, Development and Acquisition Costs

     Finding, development and acquisition costs, or FD&A costs, are the costs of adding reserves. FD&A costs include reserve revisions, costs associated with acquiring undeveloped land, seismic data, drilling equipment, tie-in and field facilities as well as acquisition costs related to reserves purchased. FD&A costs, calculated in accordance with National Instrument 51-101 (“NI 51-101”) of the Canadian Securities Administrators entitled “Standards of Disclosure for Oil and Gas Activities” in Canada, recognize changes in future capital necessary to place non-producing reserves on production. In addition to calculating FD&A costs in accordance with NI 51-101, we also calculate finding and development costs (“F&D costs”) excluding acquisition costs. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total F&D costs related to reserves additions for that year. The following table presents a summary of our FD&A costs and F&D costs for proved reserves:

	Years Ended December 31
	2004		2003		2002		3 Year Average
FD&A costs ($/boe)	$	14.91	$	20.91	$	8.15	$	13.83
F&D costs ($/boe)	$	14.96	$	21.71	$	8.16	$	12.75

     The adoption of the more stringent requirements of NI 51-101 in 2003 and the recognition of significant future capital in that year resulted in the increase in FD&A and F&D costs in 2003.

Liquidity and Capital Resources

	As at September 30,			As at December 31,
	2005			2004			2003			2002
	(in thousands, except ratios and percentages)
Working capital deficiency(1)	$	35,144		$	603		$	(21,843	)	$	(32,139	)
Current bank debt		—			220,000			164,500			40,000
Long term bank debt		260,000			—			—			—
9.90% Notes		191,582			198,594			213,246			260,634
	$	486,726		$	419,197		$	355,903		$	268,495
Shareholders’ equity
Capital stock	$	226,119		$	135,526		$	131,577		$	128,079
Contributed surplus		7,611			3,840			760			—
Retained earnings		323,311			284,712			224,569			112,039
	$	557,041		$	424,078		$	356,906		$	240,118
Debt to Adjusted EBITDA(2) (3)					2.04	x		2.02	x		2.54	x
Debt to market capitalization(2) (4)		18	%		25	%		35	%		34	%

(1) Working capital excludes unrealized risk management items.

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(2)	Debt includes current and long-term portion.
(3)	Adjusted EBITDA is calculated as net earnings before interest and finance charges, depletion and depreciation, unrealized foreign exchange gains and losses, stock-based compensation, unrealized risk management gains and losses and income taxes and less “MPP related adjustments”, which represents depletion and depreciation and income taxes attributable to MPP.
(4)	Market capitalization is based on our total number of shares outstanding and share price at the particular dates listed.

     On July 5, 2005, we renewed our senior secured credit facilities, increasing the authorized amount of the facilities to $274 million from $240 million. The facilities reach term on July 5, 2006 and mature on July 6, 2007. We had $260 million drawn on the facilities at September 30, 2005. At December 31, 2004, we had drawn $220 million on our then available $240 million senior secured credit facilities. Debt levels at December 31, 2004 increased over 2003 as total capital expenditures exceeded our cash flow in 2004.

     The principal amount of our outstanding 9.90% Notes has remained at US$165 million since their issuance on May 8, 2002. The aggregate value of these notes shown on the consolidated balance sheets varies in response to movement in the Canadian/U.S. dollar exchange rate. On November 29, 2005, we completed a tender offer to repurchase the 9.90% Notes. On November 22, 2005, the Issuer sold its Initial Notes in a private placement exempt from the registration of the Securities Act and pursuant to applicable prospectus exemptions under Canadian securities laws and the Initial Purchasers of these Initial Notes then resold them in reliance on other exemptions from the registration requirements of the Securities Act and such prospectus exemptions. We used a portion of the net proceeds from the offering of the Initial Notes to fund the purchase by Compton Holdings of the US$158,250,000 aggregate principal amount of 9.90% Notes tendered in that offer. See “Use of Proceeds”.

     On February 18, 2005, we issued 7.5 million common shares at a price of $12.00 per share for gross proceeds of $90 million. Funds from the issue were used initially to repay a portion of our then current indebtedness and thereafter to expand and accelerate our 2005 capital expenditure program.

     We have historically funded our exploration, development and exploitation capital program through internally generated cash flow and have financed acquisitions through bank debt, the issuance of common shares or a combination thereof. Our accelerated drilling program has recently been, and will continue to be, funded through internally generated cash flow, the issuance of additional equity and debt, and non-core property sales.

     We expect cash flows from operations, the common share equity issue we completed in February 2005, minor non-operated property dispositions and funds available under our existing senior secured credit facilities will together be more than sufficient to finance our operations and our planned capital expenditures of $390 million in 2005.

     Contractual Obligations

     As part of our normal business, we have entered into arrangements and incurred obligations that will impact our future operations and liquidity, some of which are reflected as liabilities in the consolidated financial statements. The following table summarizes our contractual obligations as at December 31, 2004:

		Payments Due By Period
		Less Than						After
		1 Year		1-3 Years		4-5 Years		5 Years
		(in thousands)
Payment of 9.90% Notes due 2009(1)		$	—	$	—	$	198,594	$	—
Distributions to partners(2)			9,172		27,516		3,057		—
Operating leases			5,025		15,533		—		—
Office rent	��		1,268		1,605		—		—
Capital lease obligations			38		50		—		—
Other long-term obligations			98		193		—		—
Total		$	15,601	$	44,897	$	201,651	$	—

(1)	Excludes scheduled interest payments and the purchase of $US158,250,000 of our 9.90% Notes by Compton Holdings on November 22, 2005.
(2)	Reflects mandatory payments to be made by us to MPP under the MPP processing agreement that are made directly to the MPP Limited Partner. Distributions to partners does not include the operating fee to be paid under the MPP processing agreement, which equates to the

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operating costs of MPP’s gas plant and related facilities that have not been recovered through revenues from processing gas for third parties. In addition, distributions to partners does not include amounts we may be obligated to pay upon certain events of default under the arrangements with MPP. See “Description of Material Indebtedness and Other Commitments — Mazeppa Processing Partnership and Related Documents”.

     We have the right, and currently intend, to request that the term and maturity of our senior secured credit facilities be extended, from time to time, in each case for a period of 364 days, subject to our bank lenders consenting to such requests. Therefore repayment of those facilities is not included in the table of contractual obligations above. See “Description of Material Indebtedness and Other Commitments — Senior Secured Credit Facilities”. Our asset retirement obligation is not included in the table of contractual obligations above. See Note 9 to our consolidated financial statements included elsewhere in this short form prospectus.

Commitments

     To prevent the expiration of undeveloped lands, we anticipate approximately $9 million of work commitments will be required in 2005. These commitments have been included in our 2005 capital expenditure budget.

     Additional Disclosures

     Critical Accounting Estimates

     Critical accounting estimates require us to make assumptions regarding matters that are uncertain at the time the estimate is made and may have a material impact on our financial condition. A comprehensive discussion of our significant accounting policies may be found in Notes 1 and 2 to our consolidated annual financial statements. See “Index to Financial Statements”.

     Oil and Natural Gas Reserves.The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. See “Presentation of our Reserve Information”. We expect that our estimates of reserves will change with updated information from the results of future drilling, testing or production levels. Such revisions could be upward or downward. Reserve estimates have a material impact on depletion and depreciation, asset retirement expenses and impairment costs which could possibly have a material impact on our consolidated net earnings. The independent petroleum engineering and geological consulting firm of NSAI evaluated and reported on 100% of our crude oil and natural gas reserves as of December 31, 2004 and December 31, 2003. The independent petroleum engineering consulting firm of Outtrim evaluated and reported on 100% of our crude oil and natural gas reserves as of December 31, 2002.

     Depletion.Capitalized costs and estimated future expenditures to develop proved reserves, including abandonment costs, are depleted based on the proportion of estimated proved oil and natural gas reserves produced during the year compared to total proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If it is determined that properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

     In 2004, we incurred $83 million of depletion and depreciation expense. If our proved reserves were to vary by 5%, the depletion and depreciation expense would change by approximately $1 million and consolidated net earnings after tax would change by approximately $780,000.

     Impairment.In applying the full cost method of accounting, we periodically calculate a ceiling or limitation on the amount that property and equipment may be carried at on our consolidated balance sheets. An impairment exists if the undiscounted future net cash flows from proved reserves at estimated future commodity prices plus the cost of undeveloped properties is less than the carrying value of the capitalized costs. If an impairment is found to exist, the impaired properties are written down to their fair value. The fair value of the assets is calculated based on future net cash flows from proved plus probable reserves, discounted at a risk free interest rate using estimated future commodity prices, plus the cost of undeveloped properties. An impairment may result in a material loss for a particular period; however, future depletion and depreciation expense would be reduced as a result. As at December 31, 2004, our ceiling amount calculated in accordance with Canadian GAAP was approximately $1 billion in excess of the carrying value of

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the costs capitalized. As of December 31, 2004, our ceiling amount calculated in accordance with U.S. GAAP was approximately $113 million in excess of the carrying value of the costs capitalized.

     Assumptions about reserves and future prices are required to calculate future net cash flows. The assumptions made to estimate reserves have been discussed above. There is significant uncertainty in forecasting future commodity prices due to, among other things, economic and political uncertainties. We derive our estimated future prices from a consensus of price forecasts among recognized reserve evaluators. Estimates of future cash flows assume a long-term price forecast and current operating costs per boe, plus an inflation factor.

     It is difficult to determine and assess the impact of a decrease in proved reserves on impairment. The relationship between reserve estimates and the estimated undiscounted cash flows, and the nature of the property-by-property impairment test, is complex. As a result, it is not possible to provide a reasonable sensitivity analysis of the impact that a reserve estimate decrease would have on impairment.

     Asset Retirement Obligation.We are required to remove associated production equipment, batteries, pipelines and gas plants and restore land at the end of oil and natural gas operations at a specified property. We estimate these costs in accordance with existing laws, contracts and other policies. These obligations are initially measured at fair value, which is the discounted future value of the liability. This fair value is capitalized as part of the cost of the related assets and amortized over the useful life of the asset.

     An annual increase to the liability is recorded to recognize the passage of time and the impending settlement of the obligation. The liability is impacted by any changes in the assumptions used in the asset retirement obligation calculation. Adjustments to the estimate will be recorded as an accretion expense on the consolidated statement of earnings.

     In the future, we expect our depletion expense to decline because the discounted value of the liability on our future consolidated financial statements will be depleted, rather than the undiscounted value which is currently depleted. The lower depletion expense will be offset by the addition of the accretion expense.

     An independent environmental consulting firm was hired to assist us in the estimation of asset removal cost. The ARO cost calculations were derived from a combination of actual third-party cost quotes, EUB cost models and typical industry experience and practices. The deemed ARO liability for wells and facilities is the sum of the calculated abandonment and reclamation liabilities adjusted for designated status as active, inactive, abandoned or problem site. Information regarding environmental remediation cost and other liability issues for site specific concerns were derived from a review of historical audits and assessment reports for sites and facilities. An inflation rate of 2.0% and a credit adjusted risk free interest rate of 10.8% was used in our fair value calculation.

     Estimating future asset removal costs is difficult and requires us to make estimates because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. As a result, it is not possible to provide a reasonable analysis of the impact that changes in removal costs would have on the asset retirement obligation. If the inflation rate assumed in the ARO calculation changed by 1%, the ARO obligation would vary by $3 million. Additionally, a 1% change in the credit adjusted risk free interest discount rate would result in a $2 million change to the ARO liability.

     Changes in Accounting Policy

     The CICA adopted several new accounting standards that became effective in 2004. We chose to early adopt the Stock-Based Compensation, Asset Retirement Obligations and Oil & Gas Full Cost Accounting standards in the preparation of our 2003 consolidated financial statements. The only new standard affecting the preparation of our 2004 consolidated financial statements is hedge accounting.

     In December 2001, the CICA modified Accounting Guideline 13, “Hedging Relationships” (“AcG-13”). AcG-13 establishes certain conditions where hedge accounting may be applied, effective for fiscal years beginning on or after July 1, 2003. Additionally, the EIC amended their guidance in EIC 128, “Accounting for Trading, Speculative or Non-Trading Derivative Financial Instruments,” to require that all derivative instruments that do not qualify for hedge

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accounting or are not designated as hedges, be recorded on the consolidated balance sheets with changes in fair value recognized in earnings.

     We adopted the modified AcG-13 effective January 1, 2004 and elected not to designate any of our current risk management activities as accounting hedges under AcG-13. We currently account for all derivatives using the mark-to-market accounting method. The impact on our consolidated financial statements at January 1, 2004 was an increase in liabilities of $11 million and a deferred loss of $11 million, which will be recognized as the applicable contracts expire.

Market Risk

     Our operations are subject to risks normally associated with the oil and natural gas industry. We are exposed to financial risks, including commodity price fluctuations and changing expenditure costs due to shifts in market conditions. Commodity prices are driven by supply, demand and market forces outside our influence; however, our product mix is diversified to minimize exposure to price movements in any one commodity. We sell our natural gas and crude oil production in various markets to avoid undue exposure to any one market. When appropriate, we ensure that parental guarantees or letters of credit are in place to minimize the impact of any event of default under applicable agreements.

     We monitor and focus our expenditures to reflect commodity prices and production changes, and we continuously scrutinize market conditions and opportunities. From time to time, we enter into hedge transactions to manage fluctuations in commodity prices and foreign currency exchange rates. We do not participate in derivative or other financial instruments for trading purposes, and commodity price contracts may not exceed 50% of our production. We consider an abundance of information from a variety of sources before entering into a hedging transaction. The Audit, Finance and Risk Committee of our board of directors regularly reviews our hedging strategies and transactions.

     We enter into commodity price contracts to hedge anticipated sales of oil and natural gas production to protect cash flows for our capital expenditure programs. Commodity price risk is actively managed by using costless collars, fixed priced contracts and by balancing physical and financial contracts in terms of volumes, timing of performance and delivery obligations. Net open positions may exist or may be established to take advantage of market conditions. Net earnings for the year ended December 31, 2004 include losses of $7 million (2003 — $5 million loss; 2002 — $1 million gain) on these transactions.

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     The following table summarizes commodity and fixed-price contracts that were in place during the third quarter of 2005 and/or that are currently in place:

Commodity	Type	Term	Volume	Average price		Index
Natural gas	Collar	Apr. 2005 – Oct. 2005(1)	45,000 GJ/d	$	6.28 – $  8.87	AECO
	Collar	May 2005 – Oct. 2005(1)	10,000 GJ/d	$	6.75 – $  9.33	AECO
	Collar	Nov. 2005 – Mar. 2006	40,000 GJ/d	$	8.29 – $12.14	AECO
	Fixed	Nov. 2005 – Mar. 2006	10,000 GJ/d	$	8.60	AECO
	Collar	Apr. 2006 – Oct. 2006	20,000 GJ/d	$	7.75 – $11.60	AECO
Crude oil	Collar	Jan. 2005 – Dec. 2005	1,000 bbls/d	US$	35.00 – US$48.75	WTI
	Collar	Feb. 2005 – Dec. 2005	500 bbls/d	US$	43.00 – US$49.51	WTI
	Collar	Jan. 2006 – Dec. 2006	2,000 bbls/d	US$	55.00 – US$76.25	WTI

(1) Expired as of October 31, 2005.

     We consider entering into longer term contracts with suppliers, where appropriate, to mitigate risks from shifts in costs resulting from changes in industry and market conditions. We have no control over government intervention or taxation levels on the industry.

     In the future, it is likely that we will be required to raise additional capital by way of 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 may be required to forego attractive business opportunities. We are committed to maintaining a strong balance sheet, combined with a flexible capital expenditure program that can be adjusted to capitalize on or reflect acquisition opportunities or a tightening of liquidity sources.

     Interest Rate Risk Management

     Concurrent with the closing of the offering of the 9.90% Notes in May of 2002, we negotiated a cross currency interest rate swap. The swap, which converted fixed rate U.S. dollar interest obligations into floating rate Canadian dollar interest obligations, was entered into to fix the exchange rate on interest payments and to take advantage of lower floating interest rates. The terms of the swap correlates with the terms of the indenture governing the 9.90% Notes and has resulted in an effective interest rate of 7.24% (2003 — 7.85%). At December 31, 2004, there was an unrealized hedge loss of $4 million (2003 — $9 million), as calculated on a mark-to-market basis by the issuer of the instrument.

     Foreign Currency Exchange Rate Risk Management

     We 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 on reference prices denominated in U.S. dollars, while the majority of our expenses are denominated in Canadian dollars. When appropriate, we enter into agreements to fix the Canadian/U.S. dollar exchange rate in order to manage the risk. No foreign currency agreements were in place in 2004. In 2003, a $2 million gain was realized and included in revenue as a result of foreign currency contracts.

     The foreign exchange gain on the consolidated statements of income is primarily an unrealized gain resulting from the translation of our US $165 million 9.90% Notes. The 9.90% Notes are recorded on the consolidated balance sheets at the year-end exchange rate with any differences booked as an unrealized foreign exchange gain or loss. The Canadian dollar closed on December 31, 2004 at US$0.8310 compared to US$0.7738 at December 31, 2003, resulting in a $15 million unrealized foreign exchange gain in 2004. The cumulative unrealized foreign exchange gain from the date of issue of the notes in May 2002 is approximately $60 million.

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BUSINESS

     The Company

     We are an Alberta-based independent public company actively engaged in the exploration, development and production of natural gas, crude oil and natural gas liquids in the WCSB. As of September 30, 2005, we held working interests in 2,501 gross (1,350 net) wells, and as of December 31, 2004, we held working interests in 1,019,854 gross (729,429 net) acres of undeveloped land. As of December 31, 2004, we had established total proved reserves of 97,099 mboe gross (78,767 mboe net) with a PV-10 value of approximately $1 billion. See “—Reserves.” Of these reserves, approximately 76% were natural gas reserves and approximately 87% were proved developed reserves. As of December 31, 2004, we operated approximately 88% of our proved reserves.

     We are primarily focused on unconventional natural gas resource plays in the WCSB. Unconventional natural gas reserves include tight gas, coal bed methane (“CBM”) and shale gas. Tight gas reserves are typically abnormally pressured systems that produce little or no water and experience high declines during the first years of production, reducing to very low decline rates thereafter. Compton uses the term resource play to describe an accumulation of hydrocarbons known to exist over a large area and/or a thick vertical section. Resource plays typically include numerous repeatable drilling opportunities and predictable results in terms of production rates and reserves, resulting in lower geological and/or commercial development risk. We are targeting unconventional tight gas, primarily in basin centered gas systems, and coal bed methane resource plays.

     Our exploration, development and exploitation activities are concentrated principally in three core areas:

• Southern Alberta.As of December 31, 2004 we held approximately 492,655 gross (397,799 net) acres of undeveloped land in southern Alberta. Our activities target unconventional natural gas reserves in the Plains Belly River, Horseshoe Canyon Edmonton coalbed methane, Hooker Basal Quartz, thrusted foothills Belly River (Callum) and Wabamun/Crossfield formations. The area is prospective for multiple natural gas-charged zones. In 2004, we drilled 101 gross (88 net) wells in southern Alberta with a 92% success rate. From January 1 to September 30, 2005, we drilled 135 gross (127 net) wells in southern Alberta with a 99% success rate.

• Central Alberta. As of December 31, 2004, we held approximately 256,454 gross (164,568 net) acres of undeveloped land in central Alberta, the majority of which is located approximately 100 kilometres west of Edmonton. Our central Alberta operations target unconventional natural gas reserves of a similar nature to our reserves in the Hooker Basal Quartz formation in southern Alberta. In 2004, we drilled 46 gross (32 net) wells in central Alberta with an 83% success rate. From January 1 to September 30, 2005, we drilled 55 gross (27 net) wells in central Alberta with a 100% success rate.

• Peace River Arch. As of December 31, 2004, we held approximately 117,040 gross (76,384 net) acres of undeveloped land in the Peace River Arch area. The Peace River Arch area contains multi-zone potential for exploration and development opportunities. This area includes both light oil production at Cecil/Worsley and opportunities for natural gas exploration at Howard and Pouce Coupe. In 2004, we drilled 39 gross (26 net) wells in the Peace River Arch area with a 92% success rate. From January 1 to September 30, 2005, we drilled 85 gross (78 net) wells in the Peace River Arch area with an 86% success rate.

     Corporate Structure

     Compton Petroleum Corporation was incorporated by articles of incorporation pursuant to the provisions of theBusiness Corporations Act(Alberta) on October 15, 1992, and we commenced active business operations in July 1993. Our head and principal office is located at Suite 3300, 425 - 1^st Street S.W., Fifth Avenue Place, East Tower, Calgary, Alberta, Canada, T2P 3L8. Our general telephone number is (403) 237-9400. Our common shares are listed and posted for trading on the Toronto Stock Exchange (“TSX”) under the trading symbol “CMT”. Our common shares began trading on the New York Stock Exchange on December 6, 2005 under the ticker symbol “CMZ”.

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

     Compton Finance is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Finance has no independent operations and has no significant liabilities or assets other than the Notes, its equity interest in Hornet Energy Ltd. and intercorporate indebtedness. The registered office of Compton Finance is 4300 Bankers Hall West, 888 – 3^rd Street S.W., Calgary, Alberta, Canada T2P 5C5.

     Compton Holdings is a wholly-owned subsidiary of Compton Petroleum Corporation. Compton Holdings has no independent operations and has no significant liabilities or assets other than owning US$158,250,000 aggregate principal amount of 9.90% Notes and intercorporate indebtedness. The registered office of Compton Holdings is 4300 Bankers Hall West, 888 – 3^rd Street S.W., Calgary, Alberta, Canada T2P 5C5.

     The following chart shows our corporate structure, including significant subsidiaries.

(1)	Compton Petroleum Corporation, Compton Holdings, Hornet Energy Ltd. and Compton Petroleum partnership will be guarantors of the Exchange Notes upon completion of this offering.
(2)	Reflects ownership as of September 30, 2005. Ownership is determined semi-annually based on value of assets contributed.

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Competitive Strengths and Operating Strategies

     Our plan is to grow our reserves and optimize the economic recovery of reserves from our core areas and other areas where we have technical expertise. We aim to achieve this objective by focusing on the efficient exploration, development and exploitation of our properties, controlling operating costs, adding economic reserves and production and making strategic acquisitions in our core areas. We believe that our experienced management, and professional and technical and support staff are well suited to carry out our business plan and our current exploration, development, exploitation, production, engineering, financial and administrative functions.

     Our operating strategy includes the following components:

     Concentrate on Core Areas. We focus on our core areas, which provide us with a balanced portfolio of exploration, development and exploitation prospects. These areas are the geographic focus of our seismic database rights, which includes conventional two-dimensional seismic data covering 72,800 kilometres and three-dimensional seismic data covering 3,000 square kilometres, and are areas in which our management and staff have significant technical expertise and operational experience. Our intention is to generate exploration opportunities and to increase our undeveloped land base within the WCSB.

     Focus on Unconventional Natural Gas in Large Resource Plays. As of December 31, 2004, approximately 76% of our proved reserves were natural gas, of which approximately 75% were unconventional natural gas reserves. We have gained considerable technical expertise and achieved significant success in exploring for unconventional, larger natural gas accumulations in the WCSB. We plan to continue to focus on finding and developing these types of natural gas opportunities because of their generally lower decline curves and higher economic return over the life of the reserves compared to conventional natural gas opportunities. The large scale nature of our resource plays also offers multiple low-risk drilling locations resulting in lower costs and decreased exploration risk.

     Pursue Growth Through the Drill Bit Complemented by Selective Acquisitions. We plan to continue to reinvest internally-generated cash flow and to use other sources of capital to fund the growth of our exploration and development programs and to further increase our undeveloped land base to maintain a growing inventory of drilling prospects in our core areas. In 2004, we began an accelerated drilling program. Based on our plans for an annual 500 to 700 gross well drilling program, we have over five years of drilling inventory on our existing lands. Most of these planned wells are expected to be in close proximity to producing wells in our existing core areas. Our drilling success rate has been at or above 90% for each of the past three years, giving us confidence in our ability to successfully grow reserves and production from this extensive inventory of drilling locations.

     Control 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 critical infrastructure in each of our three core areas. Through a management agreement, we manage the activities of MPP, the owner of major natural gas gathering and processing facilities in southern Alberta. We process a majority of our production from southern Alberta at these facilities through a processing agreement with MPP. As of December 31, 2004, we operated approximately 88% of our proved reserves and had a 72% average working interest in our undeveloped lands. Being an operator allows us to exercise discretion in determining the timing and methodology of our ongoing exploration, development and exploitation programs. We expect to continue to expand our working interest in our core areas to maximize operating efficiencies.

     Maintain Financial Flexibility. We are committed to maintaining financial flexibility sufficient to allow us to pursue our full-cycle exploration program in periods of low commodity prices and to respond to opportunities for strategic acquisitions as they arise. We have historically funded our exploration, development and exploitation capital program through internally generated cash flow and have financed acquisitions through bank debt, the issuance of common shares or a combination thereof. Our accelerated drilling program has recently been, and will continue to be, funded through internally generated cash flow, the issuance of additional equity and debt, and non-core property sales. Other components of our financial discipline include establishing appropriate leverage ratios and maintaining an active commodity hedging program.

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Principal Properties

     The table set forth below summarizes our average daily production, before deducting royalties, from our core areas for the year ended December 31, 2004:

					Natural Gas
	Natural Gas		Crude Oil		Liquids		Total
	(mcf/d)		(bbls/d)		(bbls/d)		(boe/d)
Southern Alberta		78,256		143		1,428		14,614
Central Alberta		25,231		1,356		509		6,070
Peace River Arch		16,693		2,613		158		5,553
Total		120,180		4,112		2,095		26,237

     Oil and Gas Wells and Properties

     The table set forth below summarizes the location of our interests as at September 30, 2005, in natural gas and crude oil wells that are producing or which we consider to be capable of production.

Area	Producing
	Natural Gas				Shut-in Natural				Producing				Shut-in Crude
	Wells				Gas Wells				Crude Oil Wells				Oil Wells				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Southern Alberta		658		440		149		135		221		157		9		7		1,037		739
Central Alberta		479		233		63		36		172		78		4		4		718		351
Peace River Arch		139		51		13		6		567		180		27		23		746		260
Total wells		1,276		724		225		177		960		415		40		34		2,501		1,350

     The table set forth below shows our percentage of revenue for natural gas, crude oil, and natural gas liquids from each of our core areas during the years ended December 31, 2002, 2003 and 2004.

	Year Ended December 31, 2004
							Natural Gas
	Natural Gas			Crude Oil			Liquids
Southern Alberta		63.3	%		3.4	%		66.8	%
Central Alberta		20.4	%		31.9	%		23.8	%
Peace River Arch		13.5	%		61.4	%		7.4	%
Total		97.2	%		96.7	%		98.0	%

	Year Ended December 31, 2003
							Natural Gas
	Natural Gas			Crude Oil			Liquids
Southern Alberta		65.1	%		5.7	%		62.0	%
Central Alberta		16.4	%		40.0	%		20.7	%
Peace River Arch		14.6	%		50.6	%		13.5	%
Total		96.1	%		96.3	%		96.2	%

	Year Ended December 31, 2002
							Natural Gas
	Natural Gas			Crude Oil			Liquids
Southern Alberta		69.2	%		16.7	%		69.9	%
Central Alberta		12.8	%		32.0	%		14.1	%
Peace River Arch		14.2	%		47.3	%		11.9	%
Total		96.2	%		96.0	%		95.9	%

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     Southern Alberta

     Southern Alberta continues to be the focus of our activities. As of December 31, 2004, we held approximately 781,382 gross (638,643 net) acres of land in southern Alberta. Additional upside exists in the shallower Horseshoe Canyon (Edmonton formation) coals, the Plains Belly River, thrusted foothills Belly River (Callum), Hooker Basal Quartz and the Wabamun/Crossfield formations. In 2004, we drilled 101 gross (88 net) wells in southern Alberta with a 92% success rate. From January 1 to September 30, 2005, we drilled 135 gross (127 net) wells in southern Alberta with a 99% success rate.

     Horseshoe Canyon Coalbed Methane. As of December 31, 2004, we held approximately 712,279 gross (597,980 net) acres of land in southern Alberta within the dry Horseshoe Canyon CBM fairway. As of December 31, 2004, we had an average working interest of 89.6% in this area. Following an internal geological assessment of the CBM potential in our lands, we are proceeding to quantify the CBM resource base.

     We had insignificant CBM reserves booked as at December 31, 2004, despite having 5 wells on continuous production. Quantifying the reserve and delivery potential of the Edmonton/CBM over our large land inventory has been one of our key objectives in 2005. From January 1 to September 30, 2005, we drilled 19 gross (18.2 net) wells targeting the Horseshoe Canyon coals and, as of September 30, 2005, we had 4 CBM pilot projects underway, with results expected by the middle of the fourth quarter of 2005. The pilot projects will not delay our plan to continue uphole recompletions of existing Plains Belly River wells in the area.

     Prior to December 31, 2004, we had drilled 260 gross (231.7 net) Plains Belly River wells across our southern Alberta core area, primarily on single section spacing. These existing wells were drilled through the Edmonton formation targeting the Plains Belly River zone. Behind pipe are unperforated coals and Edmonton sands of similar quality and quantity to successful competitor CBM plays on lands that lie immediately to the north and south of our landholdings. We expect to have over 355 wellbores available for uphole CBM recompletions by December 31, 2005, an increase of 93 during the year.

     We have an extensive network of low pressure pipelines and strategically placed compressors throughout southern Alberta to produce our Plains Belly River natural gas wells. As a result, we expect little additional infrastructure will be required to initiate our Edmonton/CBM production.

     Plains Belly River.The Plains Belly River consists of 5 to 6 multi-stacked sands, which, as of December 31, 2004, occurred extensively over 712,279 gross (597,980 net) acres of our southern Alberta core area. We have an average working interest of 84% in our properties in the Plains Belly River. Generally, wells in this area initially produce approximately 150 to 200 mcf/d and on average cost approximately $500,000 to drill, complete, equip and tie-in. We estimate natural gas-in-place could be in the range of 6 to 11 bcf and recoveries may average 0.5 bcf or more per well. Ultimate recoveries will depend on well density. We believe that 4 to 6 wells per section will optimize recovery of the Plains Belly River natural gas. We drilled 71 gross (65 net) wells at Centron, Gladys and Brant in the first three quarters of 2005. All wells encountered multiple pay zones, attesting to our successful use of seismic data in identifying producible sands. As of September 30, 2005, we have drilled 93 gross (86.9 net) wells targeting the Plains Belly River sands. The pipeline and compression system that we own and operate in southern Alberta is extensive and we believe it allows us to optimize our production in this area.

     Callum Thrusted Belly River. Applying expertise developed in our Plains Belly River exploration, we are targeting thrusted, foothills multiple Belly River tight sandstones at Callum. We have an average 59% working interest in 69,103 gross (40,663 net) acres of land in the area. Based on limited initial drilling results, we estimate the potential natural gas in place to be 80 bcf per section, with ultimate recoveries depending on well density.

     In 2004, we drilled 3 directional wells from a pad constructed immediately south of the Callum gas plant, and we drilled 2 additional wells north of the plant. Results were encouraging; however, we believe completion design is the key to maximizing production from our properties in this technically challenging area.

     Quarter section spacing over nine sections was approved by the EUB in the third quarter of 2004. Drilling in the Callum area is completed from pads with multi-well capability. Each new well costs approximately $2.5 million to drill, complete, equip and tie-in, with 6 to 8 wells required per section to fully develop our properties in this area. As of

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September 30, 2005, we have drilled 1 gross (0.6 net) well in this area, with recent completions averaging approximately 1 mmcf/d per well.

     Hooker Basal Quartz. The Hooker trend targets tight Lower Cretaceous Basal Quartz sandstones. This play covers an extensive area of approximately 222,138 gross (195,116 net) acres, with our working interest averaging 75%. Current production extends over four townships, with the outer boundaries of the play continuing to be expanded. To date, we have drilled 126 gross (102 net) natural gas wells on the Hooker trend. As of September 30, 2005, the EUB has approved 2 wells per section spacing across over 30,000 acres in the pool, and as such, the majority of the southern portion of the pool has been drilled on 2 wells per section spacing. We have applied to the EUB for further downspacing in the northern portion of the pool and are awaiting a decision on the applications. We are currently completing detailed engineering and geological studies to evaluate the feasibility of further downspacing in the Hooker pool.

     Our wells in the Hooker area cost an average of $1.5 million to drill, complete, equip and tie-in, while production initially averages 1.7 mmcf/d. Our mapping suggests this play has the potential to grow to nine townships with reserves in place of up to 15 to 20 bcf of natural gas per section. The same work suggests the Hooker trend has the potential to contain up to 1.5 tcf of gas-in-place potential, net to us. With recoveries of 65%, we estimate Hooker’s resource potential to be in excess of 500 bcf of net gas reserves.

     In 2004, we drilled 24 gross (20.5 net) natural gas wells, extending the pool boundary 5 miles to the north and 1.5 miles to the southeast. We have received downspacing approval on the southeast Hooker extension and are currently proceeding with an additional application for downspacing at the northern end of Hooker. During the first three quarters of 2005, we drilled 15 (15 net) natural gas wells.

     Central Alberta

     Central Alberta provides us with excellent exploration and development drilling opportunities using techniques gained through years of experience with tight gas drilling in southern Alberta. We hold 484,480 gross (260,480 net) acres of land, the majority of which located approximately 100 kilometres west of Edmonton. In 2004 we drilled 46 gross (32 net) wells with an 83% success rate. From January 1 to September 30, 2005, we drilled 55 gross (27 net) wells in central Alberta with a 100% success rate. We plan to drill 9 wells in the last quarter of 2005.

     Niton Gething. The Niton area is characterized by multi-zone, deep basin type targets analogous to the southern Alberta Hooker area. We have acquired 136,830 gross (103,341 net) acres of land in the area, with an average working interest of 75%. In 2004, we drilled 15 gross (13.7 net) natural gas wells. We anticipate the natural gas-in-place could be in the range of 10 to 12 bcf per section, with a projected recovery of 75%. In 2004, we received downspacing approval from the EUB on 18 sections for 2 wells per section, with further downspacing approval pending. We expect 2 to 3 wells per section will be required to fully develop this area.

     We drilled 17 gross (13.1 net) natural gas wells at Niton during the first three quarters of 2005, with all wells encountering multiple pay zones. Based on the successful drilling results in the first three quarters of the year, we have identified 25 drilling locations which are in the process of being acquired. With 2 rigs drilling in central Alberta, we anticipate a timely completion of our 2005 budgeted 26 well program at Niton.

     Peace River Arch

     The Peace River Arch area, located north of Grande Prairie, contains multi-zone potential for exploration and development opportunities. This area includes both light oil production at Cecil/Worsley and natural gas exploration at Howard, Pouce Coupe and Progress. We hold 115,575 gross (82,163 net) acres of land in the area. In 2004, we drilled 39 gross (26 net) wells in the Peace River Arch with a 92% success rate. From January 1, to September 30, 2005, we drilled 85 gross (78 net) wells in the Peace River Arch area with an 86% success rate.

     Cecil/Worsley. We hold 123,840 gross (80,922 net) acres of land in the Cecil/Worsley area. This area has been our primary source for crude oil production in recent years. Together, we estimate the Cecil and Worsley Charlie Lake pools hold in excess of 200 million barrels of oil-in-place. We drilled 10 gross (10 net) wells at Worsley in 2004, doubling the estimate of original oil-in-place. As a result of our success with two existing waterflood pilots, we made an application to the EUB for a pool-wide waterflood on the Charlie Lake H and J pool, with approval being granted in

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February 2005. We project that waterflooding in the Worsley Charlie Lake H and J pool will increase the ultimate recovery rate from 15% to 25%. In the first three quarters of 2005, we expanded pipelines and water handling facilities in the Worsley area to prepare for implementation of the full scale waterflood. A battery expansion was also completed to accommodate future drilling plans.

     Our strong drilling results at Worsley have continued in 2005. We drilled 54 gross (54 net) wells targeting the Charlie Lake “H” and “J” pools in the first three quarters of 2005, with wells showing initial crude oil production of approximately 90 boe/d each. Due to the success of our drilling program in the first half of the year, we have expanded our 2005 Worsley drilling program and now expect to drill 50 gross (50 net) wells during 2005.

     Howard, Pouce Coupe and Progress. Our operations in the southern portion of the Peace River Arch area include the Howard, Pouce Coupe and Progress fields. These three fields are mostly non-operated and capital commitments are dependent on how aggressively our working interest partners elect to develop these fields. We plan to drill 4 wells in this area in 2005.

Infrastructure

     Southern Alberta Facilities. We believe that our arrangements with respect to the southern Alberta sweet and sour gas Mazeppa processing facilities and pipeline give us a competitive advantage in this core area. On June 1, 2004, a 45 mmcf/d sweet natural gas expansion at the Mazeppa gas plant was completed, resulting in 90 mmcf/d sour and 45 mmcf/d sweet natural gas processing capacity. We gained operational control and management of the Mazeppa and Gladys gas plants and related infrastructure through the acquisition of the facilities by MPP in July 2003. See “Description of Material Indebtedness and Other Commitments — Mazeppa Processing Partnership and Related Agreements” for a further discussion of our processing and other arrangements with MPP. With the completion of the Mazeppa sweet gas expansion, our net processing capacity in southern Alberta is now 200 mmcf/d. We expect that available processing capacity will be sufficient to accommodate our planned production additions for the next few years. Future expansions, when required, can be undertaken by us.

     We also own and operate a low-pressure sweet gas gathering system that currently services up to 300 existing Plains Belly River natural gas wells in southern Alberta. This pipeline system is currently 311 kilometres long. Associated field compressors and centralized dehydration systems are designed to produce low pressure Plains Belly River natural gas, and we believe they will accommodate future development of Horseshoe Canyon CBM drillwells. Compressor capacity on this low-pressure natural gas gathering system is capable of 50 to 60 mmcf/d and is independent of the MPP facilities. This pipeline and compression system services the Centron, Gladys, Brant and Vulcan fields and combined with the compression systems that we own, gives us a competitive advantage in our southern Alberta core area.

     We operate and own a 30 mmcf/d natural gas plant at Callum with a 50% working interest. We also own a 7.9% working interest in a 55 mmcf/d sour gas plant located at Vulcan and a 31% working interest in a 23 mmscf/d sweet gas plant located at Shouldice. We anticipate that our future Plains Belly River and Horseshoe Canyon CBM wells will be able to use these plants at a competitive advantage over non-owners of such facilities.

     Central Alberta Facilities.In central Alberta, we have working interests in two natural gas plants and one oil battery. Our McLeod River natural gas plant was operating at maximum capacity in the third quarter of 2004 as a result of our successful drilling program at Niton. This gas plant was expanded from 10 mmcf/d to 20 mmcf/d in the fourth quarter of 2004. A 10 mmcf/d booster compressor at Niton was installed and became operational early in the third quarter of 2004.

     Also at Niton, we own a 2% working interest in a 90 mmcf/d sour gas plant that is currently operated at 30% capacity. Approximately one-third of our Niton area natural gas is processed at this facility. The other two-thirds is processed at our McLeod River natural gas plant. We expect that based on our current levels of drilling activity in central Alberta, the McLeod River natural gas plant will be at full capacity by December 31, 2005, at which time the McLeod River and Niton plants will be connected to allow natural gas to be offloaded to Niton to maximize our cash flow netbacks.

     Peace River Arch.In the Peace River Arch area, we have working interests in four major natural gas plants and three oil batteries. At Worsley, we have expanded our oil and water handling facilities to accommodate our planned

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100 well drilling program for 2005 and 2006. The Worsley oil battery is capable of handling approximately 6,000 bbls/d. Water injection pumps designed to handle 8,000 bbls/d of water have recently been installed. The sour gas plant at Worsley has recently been expanded to 7.5 mmcf/d. Our facility engineering group is currently reviewing installing a larger amine unite at Worsley that will increase the natural gas handling capacity to 15 mmcf/d. The Worsley oil battery will require a second free water knockout to expand fluid handling capacity to 10,000 bbls. We expect the battery and natural gas plant expansion work to be completed by March 31, 2006.

     At Cecil, we own a 40% working interest in a 9 mmcf/d natural gas plant, and an 18% working interest in a 56 mmcf/d natural gas plant. Oil batteries are located each of these plants, in which we have a 40% working interest. We also own a 100% working interest in another Cecil oil battery. We believe these facilities are sufficiently sized to handle our planned horizontal drilling program at Cecil.

     At Progress, we own a 5% working interest in a 140 mmcf/d sour gas plant. This plant processes our natural gas produced at our Pouce Coupe fields.

Drilling Summary

     The table set forth below summarizes our drilling results for the years ended December 31, 2004, 2003 and 2002. Of the 186 gross (146 net) wells drilled in 2004, 77% were classified as development wells and 23% were classified as exploratory wells, compared to 57% and 43% respectively in 2003. The higher percentage of development wells in the current year reflects the increasing maturity of our oil and gas plays.

	Natural Gas			Oil		D&A		Total		Net		Success
Year Ended December 31, 2004
Southern Alberta		93	(1)		—		8		101		88		94	%
Central Alberta		38			—		8		46		32		83	%
Peace River Arch		8			28		3		39		26		92	%
2004 Total		139			28		19		186		146		90	%
2003 Total		131			23		15		169		137		93	%
2002 Total		64			14		9		87		64		90	%

(1) Includes two standing, cased wells.

     The following table summarizes our 2005 drilling results from January 1 to September 30, 2005.

	Natural Gas		Oil		D&A		Total		Net		Success
Southern Alberta		132		1		2		135		127		99
Central Alberta		48		7		—		55		27		100	%
Peace River Arch(1)		2		73		12		87		79		86	%
Total		182		81		14		277		233		95

(1) Includes two standing, cased wells.

     On June 22, 2005, the EUB released Decision 2005-60 regarding a recent public hearing on our application to drill up to six sour horizontal natural gas wells southeast of the City of Calgary. These wells were proposed by us as a collaborative solution to accelerate the recovery of reserves from the Okotoks Wabamun “B” Pool in advance of urban encroachment. The decision required us to advise the EUB by November 1, 2005 if we intend to continue to pursue approval of the well licenses, which we did on October 27, 2005. Since the date of the release of Decision 2005-60, several intervenors have filed or indicated they intend to file applications to appeal various aspects of the decision to the Alberta Court of Appeal and have further applied to the EUB requesting the EUB review and alter the decision. We expect that resolution of these various legal issues will take at least several months.

Recent Developments and Outlook

     We have experienced abnormally wet weather conditions in southern Alberta in 2005. These conditions have interrupted and delayed our well completions, pipeline construction and tie-ins. These delays have, in turn, impacted production growth. We now expect average production for 2005 to be in the range of 30,000 to 31,000 boe/d as

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compared to an original projection of 31,500 to 32,500 boe/d. December 2005 production is now estimated to be in the range of 35,500 to 37,500 boe/d compared to our previous estimate of 36,500 to 37,500 boe/d. We are currently producing approximately 31,000 boe/d.

     We are currently working to bring in excess of 6,000 boe/d of behind pipe production on-line as quickly as possible. Despite these wet weather conditions, we completed our 390 well drilling program this year.

     Our 2005 capital program is comprised of an accelerated drilling program designed to realize on our significant resource potential through proved reserve additions. Despite a slow start to our 2005 drilling program caused by early spring break-up and extreme wet weather conditions, we have, as of September 30, 2005, completed 71% of our 2005 drilling program.

     Since June 30, 2005, we have drilled a total of 147 gross (123 net) wells for a total of 277 gross (233 net) wells drilled from January 1 to September 30, 2005, including 2 gross (1 net) standing, cased wells. With 14 drilling rigs at work on September 30, 2005, we are the eighth most active operator in western Canada.

Reserves

     Land

     The following table provides information about the amount of developed and undeveloped land we owned as of September 30, 2005:

	Gross		Net
Developed land (acres)		712,606		423,477
Undeveloped land (acres)		1,001,525		754,603
Total		1,714,131		1,178,080

     Reserves Summary

     The table set forth below summarizes our natural gas, crude oil, natural gas liquids and sulphur reserves as of the dates indicated and the present value attributable to these reserves as of those dates, discounted at 10% using constant pricing.

     Our interests in our natural gas and crude oil properties as of December 31, 2004, have been evaluated in reports as of December 31, 2004 and December 31, 2003, prepared by the independent international integrated petroleum engineering and geological firm, Netherland, Sewell & Associates, Inc., or NSAI, in accordance with NI 51-101. The reserve information as of December 31, 2002 was evaluated in a report dated January 1, 2003, prepared by Outtrim Szabo Associates Ltd., independent petroleum engineers, or Outtrim. The summary set forth below of our reserves as of December 31, 2004 and 2003 is derived from NSAI’s reports and the summary set forth below of our reserves as of December 31, 2002 is derived from Outtrim’s report. Assumptions and qualifications relating to costs, prices for future production and other matters are included below. These reports are based on data supplied by us and on NSAI’s or Outtrim’s opinions, as applicable, of reasonable practice in the industry.

     Reserve engineering is a subjective process of estimating and evaluating underground accumulations of natural gas, crude oil and natural gas liquids that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data and the interpretation of that data by petroleum engineers. In addition, the results of drilling, testing and production activities may require revisions of reserve estimates that were made previously. Accordingly, estimates of reserves and their value are inherently imprecise and are subject to constant revision and change, and they should not be construed as representing the actual quantities of future production or cash flows to be realized from oil and gas properties or the fair market value of such properties.

     For a description of certain terms used below and certain differences between estimated proved reserves under Canadian and U.S. reserve disclosure guidelines, see “Presentation of Our Reserve Information” and “Glossary of Terms”. Reserve calculations involve the estimate of future net recoverable reserves of natural gas, crude oil and

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natural gas liquids 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 – You should not unduly rely on reserve information because reserve information represents estimates and our actual reserves could be lower than the estimates.”

	Historical as of December 31,
	2004						2003						2002
	Gross			Net			Gross			Net			Gross			Net
Proved Reserves:
Natural gas (mmcf)		445,422			359,975			404,539			326,573			401,844			314,501
Crude oil & natural gas liquids (mbbls)		21,211			17,327			15,907			12,919			13,805			10,723
Sulphur (mlt)		1,651			1,444			1,853			1,623			4,660			3,883
Natural gas equivalent (mmcfe)		582,591			472,603			511,099			413,825			512,634			402,139
Barrel of oil equivalent (mboe)		97,099			78,767			85,183			68,971			85,439			67,023
% natural gas		76.5	%		76.2	%		79.2	%		78.9	%		78.4	%		78.2	%
% proved developed		86.6	%		86.9	%		86.1	%		87.0	%		94	%		94.4	%
Estimated reserve life (years)(1)		9.9			10.5			9.1			9.7			8.9			9.2
Annual reserve replacement percentage(2)		221	%					97	%					249	%
Recycle ratio(3)		1.6	x					1.1	x					1.7	x
PV-10 (thousands)(4)				$	1,000,772					$	759,083					$	1,016,120

(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 percentage 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 field operating netback per boe in a year by our finding and development costs per boe in that year. Field operating netback per boe is calculated by dividing our annual net revenues generated from producing natural gas and crude oil and natural gas liquids volumes, net of operating costs and transportation expenses by our annual production in that year. Finding and development costs per boe is calculated by dividing our exploration and development costs incurred in the current year and the change in future development costs relating to proved reserves by the additions to proved reserves made during the current year. Finding and development costs do not include capital expenditures made by MPP.
(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 2002 were $6.00 per mcf of natural gas and $46.91 per barrel of crude oil and natural gas liquids. The prices used in 2003 were $6.09 per mcf of natural gas and $41.05 per barrel of crude oil and natural gas liquids. The prices used in 2004 were $6.79 per mcf of natural gas and $40.28 per barrel of crude oil and natural gas liquids. PV-10 does not purport to present the fair market value of our natural gas, crude oil and natural gas liquids properties and is not necessarily indicative of actual future cash flows.

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Production, Sales and Costs

     The following table provides summary data with respect to our production, before deducting royalties, and sales of natural gas, and crude oil and natural gas liquids for the periods indicated and the costs related to such production.

	Nine Months Ended September 30,				Year Ended December 31,
	2005		2004		2004		2003(1)		2002
Production:
Natural gas (mmcf)		35,459		33,395		45,120		42,990		40,807
Crude oil and natural gas liquids (mbbls)		1,974		1,676		2,317		2,162		2,374
Natural gas equivalent (mmcfe)		47,303		43,451		59,021		55,963		55,049
Barrel of oil equivalent (mboe)		7,884		7,242		9,837		9,327		9,175
Average Sales Price Per Unit(2)(3):
Natural gas (per mcf)	$	7.46	$	6.52	$	6.46	$	6.27	$	3.80
Crude oil and natural gas liquids (per bbls)	$	55.24	$	43.33	$	43.21	$	35.59	$	30.06
Natural gas equivalent (per mcfe)	$	7.89	$	6.69	$	6.64	$	6.19	$	4.12
Barrel of oil equivalent (per boe)	$	47.37	$	40.11	$	39.82	$	37.16	$	24.70
Costs:
Royalties (per mcfe)	$	1.89	$	1.56	$	1.58	$	1.48	$	0.86
Royalties (per boe)	$	11.31	$	9.38	$	9.50	$	8.85	$	5.18
Operating (per mcfe)(3)	$	1.01	$	0.92	$	0.94	$	0.89	$	0.83
Operating (per boe)(3)	$	6.07	$	5.52	$	5.66	$	5.35	$	4.96
Transportation (per mcfe)	$	0.16	$	0.14	$	0.15	$	0.15	$	0.15
Transportation (per boe)	$	0.98	$	0.84	$	0.87	$	0.91	$	0.89
General and administrative (per mcfe)(4)	$	0.30	$	0.24	$	0.26	$	0.22	$	0.18
General and administrative (per boe)(4)	$	1.82	$	1.43	$	1.55	$	1.31	$	1.07

(1)	2003 costs have been reclassified to include the impact of the consolidation of MPP. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Consolidation of Mazeppa Processing Partnership”.
(2)	Excludes the impact of hedging transactions. 2003 and 2002 amounts have been reclassified to exclude hedge gains and losses.
(3)	Prior to 2004, transportation costs were partially recorded as a reduction of revenue and partially recorded as an increase in operating expense. 2003 and 2002 amounts have been reclassified to exclude transportation charges.
(4)	Excludes stock-based compensation.

Competitive Conditions

     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 that have larger technical staffs and greater financial and operational resources than us. 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. Many of our competitors 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 in attempting to secure skilled personnel, drilling rigs, service rigs and other equipment necessary for drilling and completion of wells, as well as for access to processing facilities, pipeline and refining capacity. Currently, drilling rigs, service rigs, equipment and experienced crews are operating at or near maximum capacity in the WCSB, which has resulted in escalating drilling costs and inefficiencies. Strong demand for experienced professionals has caused a significant increase in salaries and workloads, further adding to inefficiency in the industry. In addition to increasing our costs, demand for equipment or personnel may affect the availability of that equipment or personnel to us, delaying our exploration and development activities.

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Seismic Data

     We own rights to copies of, and rights to utilize for our internal purposes, large seismic databases. The proprietary rights of such databases are owned primarily by third parties (although we own proprietary rights in some of those databases). These databases include conventional two-dimensional seismic covering 72,800 kilometres and three-dimensional seismic data covering 3,000 square kilometres. This data is concentrated primarily in areas throughout our core areas. Additionally, we have rights to use seismic data covering 6,200 square kilometres of areas in southern Manitoba. These large seismic databases are utilized by our exploration team in our exploration and acquisition decisions.

Marketing

     We sell our natural gas in a variety of markets to marketers, distributors and end users. Our natural gas production is sold primarily under short term 30-day and spot AECO indexed contracts. During 2004, approximately 12% of our natural gas production was sold to aggregators. This has remained consistent through the first three quarters of 2005.

     We sell crude oil and natural gas liquids under various short-term contracts that 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.

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 natural gas and oil companies of similar size.

     Natural gas and crude oil located in Alberta is owned predominantly by the provincial government. The provincial government grants rights to explore for and produce natural gas and oil 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 natural gas and oil located in Alberta is privately owned and rights to explore for and produce natural gas and crude oil 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 issuance 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 two to 20 years in quantities not more than 30,000 cubic metres (1.1 mcf) 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 with 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 factors such as reserve availability, transportation arrangements and market considerations.

     In addition to federal regulations, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of natural gas and oil production. Royalties payable on production from lands other than government lands are determined by negotiations between the mineral owner and the lessee. Royalties payable on production from

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government land are determined by government regulation and are generally calculated as a percentage of the value of gross production. 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, and higher prices attract higher royalty rates. Similarly, higher productivity wells and wells producing a higher grade of natural gas and crude oil are subject to higher royalty rates.

     From time to time the governments of Canada and Alberta have established incentive programs that have included royalty rate deductions, royalty holidays and tax credits for the purpose of encouraging natural gas and oil 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 (“ARTC”) Program. The ARTC program is based on a price sensitive formula and ranges between 75%, for prices for oil at or below $100 per cubic metre, and 25%, for prices above $210 per cubic metre. In general, the ARTC 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 ARTC will generally not be eligible for the ARTC. 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 impact of the ARTC on us in fiscal 2004 was $0.5 million.

     The North American Free Trade Agreement among the governments of Canada, the United States and Mexico became effective on January 1, 1994. 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:

• 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);

• 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

• 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 and to restore land disturbed by extractive operations. Also, under environmental laws we may be designated as “responsible persons”, and therefore, liable parties for remediation obligations on contaminated property. 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 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 ensure 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

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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.

Employees

     As at September 30, 2005, we had 149 full-time employees in our Calgary office and 40 full-time employees at field locations, for a total of 189 employees, which does not include employees of MPP. None of our employees are represented by a union.

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.

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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
Mel F. Belich, Q.C.		57	Director, Chairman
Irvine J. Koop, P. Eng.		59	Director
John W. Preston		58	Director
Jeffrey T. Smith, P. Geol		57	Director
John A. Thomson, C.A.		55	Director
Ernie G. Sapieha, C.A.		54	Director, President & Chief Executive Officer
Kim N. Davies, P.Geoph		49	Vice-President, New Ventures
Marc R. Junghans, P. Geol		50	Vice-President, Exploration
Norman G. Knecht, C.A.		61	Vice-President, Finance & Chief Financial Officer
Derek C. Longfield, P. Eng.		52	Vice-President, Special Projects
Tim G. Millar, LL.B.		58	Vice-President, General Counsel & Corporate Secretary
Murray J. Stodalka, P. Eng.		45	Vice-President, Operations & Engineering

     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. He was appointed Queen’s Counsel in 1996. Mr. Belich is currently Group Vice President, Corporate Law, Enbridge Inc. (an energy transportation and distribution company). He has also been Chairman and President of each of Enbridge International Inc. and Enbridge Technology Inc. and a director of numerous Enbridge affiliates, including Enbridge Pipelines (Athabasca) Inc., Enbridge Consumers Energy Inc. and Enbridge Services Inc. 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. Mr. Koop is Chairman and Chief Executive Officer of IKO Resources Inc. (a petroleum consulting firm). From November 1999 until his retirement in April 2001, Mr. Koop was President and Chief Executive Officer, Pipelines and Midstream, Westcoast Energy Inc. (an energy products and services company). 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.

     John W. Prestonhas 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 of Canada Inc., a position he has held since 1992.

     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 Honours). Mr. Smith was Chief Operating Officer of Northstar Energy Corporation (an oil and gas company) from 1995 to 1997. Mr. Smith is an independent businessman and is currently a director of Provident Energy Trust (a public crude oil and gas royalty trust) and Codero Energy Inc. (a public 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 A. Thomson, C.A., has been one of our directors since 2003. He graduated from the University of New Brunswick in 1972 with a Bachelor of Business Administration degree. He qualified as a Chartered Accountant in 1974. He has been an independent businessman since 2001. He was Senior Vice President and Chief Financial Officer of Renaissance Energy Ltd. (an oil and gas company) from 1983 to 1999.

     Ernie G. Sapieha, C.A.has been one of our directors and has been our President & Chief Executive Officer since our incorporation in 1992. Mr. Sapieha has more than 23 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.

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     Kim N. Davies, P. Geoph.was appointed Vice-President, New Ventures of Compton in 2003 and has held other executive positions with us since 1996. Ms. Davies has more than 25 years of experience in the oil and gas industry. She graduated from the University of Calgary in 1980 with a Bachelor of Science degree in physics.

     Marc R. Junghans, P. Geol.has been our Vice President, Exploration since 2002 and has held managerial roles with us since 1998. He has over 26 years experience in the oil and gas industry. He graduated from the University of Manitoba in 1978 with a Bachelor of Science, Honours, Geology.

     Norman G. Knecht, C.A.was appointed our Vice-President, Finance and Chief Financial Officer in 1997. Mr. Knecht had more than 25 years of experience in public accounting before joining us. Mr. Knecht graduated from the University of Alberta in 1969 with a Bachelor of Education degree and received his Chartered Accountant designation in 1972.

     Derek C. Longfield, P. Eng., has been our Vice President, Special Projects since 2004 and has held managerial roles with us since 2002. He has over 30 years experience in the oil and gas industry. He graduated from the University of Manitoba in 1974 with a Bachelor of Science degree in Geological Engineering.

     Tim G. Millar, LL.B.was appointed our Corporate Secretary in 1996 and Vice President, General Counsel & Corporate Secretary of Compton in 2003. 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. Prior to joining Compton, Mr. Millar was a senior partner with the Fraser Milner Casgrain LLP law firm (or its predecessors), having joined the firm in 1970. Mr. Millar is a member of the Law Society of Alberta, and Calgary, Alberta and Canadian Bar Associations.

     Murray J. Stodalka, P.Eng.was appointed our Vice-President, Operations and Engineering in 1996. Mr. Stodalka has more than 22 years of experience in the oil and gas industry. He graduated from the University of Saskatchewan in 1982 with a Bachelor of Science degree in mechanical engineering.

Compensation of Executive Officers

     The following table sets forth the compensation for our Chief Executive Officer and each of our four other most highly compensated officers (measured by base salary and bonus) (collectively, the “Named Executive Officers”) for the financial years ended December 31, 2004, 2003 and 2002.

     Summary Compensation Table

									Long Term
									Compensation
			Annual Compensation						Awards
									Number of
									Securities
									Granted
							Other Annual		Under Options		All other
Name and Principal Position	Year		Salary		Bonus(1)		Compensation(1)		(#)		Compensation(2)
Ernie G. Sapieha		2004	$	345,000	$	175,000	$	36,060		125,000	$	17,250
President & CEO		2003	$	325,000	$	160,000		—		125,000	$	16,250
		2002	$	325,000	$	250,000		—		60,000	$	16,250
Norman G. Knecht		2004	$	215,000	$	115,000	$	36,060		50,000	$	10,750
Vice-President, Finance & Chief		2003	$	205,000	$	100,000		—		50,000	$	10,250
Financial Officer		2002	$	205,000	$	150,000		—		30,000	$	10,250
Murray J. Stodalka		2004	$	215,000	$	115,000	$	36,060		50,000	$	10,750
Vice-President, Operations &		2003	$	205,000	$	100,000		—		50,000	$	10,250
Engineering		2002	$	205,000	$	100,000	$	3,599		30,000	$	10,250
Tim G. Millar(3)		2004	$	215,000	$	115,000	$	36,060		50,000	$	10,750
Vice-President, General		2003	$	187,917	$	100,000		—		50,000	$	9,396
Counsel & Corporate Secretary		2002		—		—		—		—		—
Marc R. Junghans		2004	$	215,000	$	115,000	$	36,060		50,000	$	10,750
Vice President,		2003	$	195,000	$	100,000		—		50,000	$	9,750
Exploration		2002	$	152,000	$	110,000		—		50,000	$	7,600

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(1)	In 2004, the Named Executive Officers received an amount in respect of an automobile allowance to replace the use of a Company leased automobile in 2003 and 2002 and related parking costs. Mr. Stodalka’s “Other Annual Compensation” in 2002 consisted solely of imputed interest benefits from a loan made to him by the Company (which was repaid in full in 2002) calculated in accordance with theIncome Tax Act(Canada).
(2)	“All Other Compensation” consists solely of contributions made by us on behalf of each named Executive Officer to the Employee Stock Purchase and Savings Plan. See “Management – Employee Stock Purchase and Savings Plan” for a description of such plan.
(3)	Mr. Millar was appointed Vice-President, General Counsel & Corporate Secretary on February 1, 2003.

Compensation of Directors

     The following table sets out the compensation paid during 2004 to each individual who is currently a director (other than Mr. Sapieha, the President & Chief Executive Officer, who received no compensation in his capacity as director).

	Board Retainer Fees(1)		Committee Chairman Fees			Options(4)
M.F. Belich	$	50,000	$	41,000	(2)		20,000
I.J. Koop	$	50,000	$	12,000			20,000
J.W. Preston	$	50,000		—			20,000
J.T. Smith	$	50,000	$	12,000			20,000
J.A. Thomson	$	50,000	$	6,000	(3)		20,000

(1)	Each of the directors received an additional $12,000 as reimbursement for incidental expenses in the course of fulfilling their responsibilities.
(2)	Mr. Belich received $35,000 in fees as Chairman of our board of directors and was a committee chairman from January to June, 2004.
(3)	Mr. Thomson received $6,000 in fees as a committee chairman from June to December, 2004.
(4)	All securities underlying options are common shares.

Stock Option Plan

     Our stock option plan provides that options will be granted to our directors, officers, employees and consultants for such number of common shares as the our board of directors (the “Board”) determines in its discretion, at an exercise price equal to the volume weighted average closing price of the common shares on the TSX for the five trading days immediately preceding the date on which the option is granted. Our stock option plan is administered by the Human Resources, Compensation, Environmental, Health and Safety Committee of the Board. The Board may determine the manner, time and rate of exercise of an option, which are generally fully exercisable after four years and expire no more than ten years after the grant date.

     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. Provision is made for early exercise or termination of options in the event of death, disability or cessation of employment. No financial assistance is provided to participants in connection with the exercise of options.

     The number of options available for grant under our stock option plan is a rolling maximum of 10% of the issued and outstanding common shares. The maximum number of common shares which may be reserved for issuance to insiders of Compton and their associates under our stock option plan and all of our other stock based compensation arrangements is limited to 10% of the number of common shares outstanding. The maximum number of common shares which may be issued to any one person or company under our stock option plan and all of our other stock based compensation arrangements is limited to 5% of the total number of common shares outstanding. 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 September 30, 2005, there were options outstanding to purchase 11,424,352 common shares.

     The Board is authorized to establish, amend and rescind any rules and regulations relating to our stock option plan and may correct any defect, supply any omission and reconcile any inconsistency in our stock option plan or in any option issued thereunder. The Board may amend our stock option plan to conform to any change in applicable laws, regulations or other respects in our best interests. When required, changes are subject to approval by the TSX.

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The total number of securities issuable under our stock option plan may not be increased without authorization and approval of our shareholders.

     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 his 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.

     Option Grants During the Most Recently Completed Financial Year

     The following table sets forth the options granted to each of our Named Executive Officers in our most recently completed fiscal year.

	Number of						Market Value of
	Securities		% of Total				Security Underlying
	Under		Options		Exercise		Options on Date of
	Options		Granted		Price		Grant
Name	Granted(1)		during Year		($/Security)		($/Security)		Expiry Date
Ernie G. Sapieha		125,000		6.4		7.60		7.60	June 17, 2009
Norman G. Knecht		50,000		2.6		7.60		7.60	June 17, 2009
Murray J. Stodalka		50,000		2.6		7.60		7.60	June 17, 2009
Tim G. Millar		50,000		2.6		7.60		7.60	June 17, 2009
Marc R. Junghans		50,000		2.6		7.60		7.60	June 17, 2009

(1) All securities under option are common shares.

     Aggregated Option Exercises During The Most Recently Completed Financial Year And Financial Year-EndOption Values

     The following table sets forth details of all options exercised by each of our Named Executive Officers in our most recently completed financial year. The table also details, as at December 31, 2004, 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 in-the-
					Unexercised Options at				Money Options at Financial
					Financial Year-End				Year-End
					(#)				($)
	Securities		Aggregate
	Acquired		Value
	on Exercise		Realized
Name	(#)		($)		Exercisable		Unexercisable		Exercisable		Unexercisable
Ernie G. Sapieha		400,000		2,680,000		1,056,250		248,750		9,891,325		1,068,125
Norman G. Knecht		75,000		626,500		557,500		102,500		5,091,600		447,500
Murray J. Stodalka		—		—		757,500		102,500		7,336,600		447,500
Tim G. Millar		—		—		362,500		312,500		3,005,500		1,925,750
Marc R. Junghans		30,000		169,500		200,300		125,000		1,526,124		595,625

     As at December 31, 2004, the closing price of our common shares on the TSX was $10.85 per share.

Employee Stock Purchase and Savings Plan

     We have established an employee stock purchase savings plan for all of our employees. Under our stock savings plan, employees (including executives) may elect to contribute a portion of their salary to our stock savings plan and a matching contribution is made by us, subject to the completion of 12 months of service with us. The maximum amount that an employee may elect to contribute ranges from 2% to 5% of the employee’s annual base salary and may be modified semi-annually. Contributions to our stock savings plan are used to purchase our common shares in the open market.

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Employment Contracts

     As at December 31, 2004, we had contracts with each of the Named Executive Officers. The contracts provide for compensation to these executives for loss of office in the event of a change of control, as defined in the contracts. Such compensation is the aggregate of twice (i) the executive’s current salary, (ii) 20% of current salary in lieu of benefits and (iii) the average of the executive’s previous three bonuses received. Also, each of the Named Executive Officers is entitled to a severance payment in the event of termination without cause after three years of employment with us, in the same amount. If the executive has been employed by us for less than three years, the severance payment is one half of such amount.

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RELATED PARTY TRANSACTIONS

     As of the date of this short form prospectus, none of our current or former directors, officers or employees is indebted to us. Our policy is that we will not directly or indirectly extend or maintain credit, or arrange for the extension of credit, in the form of a personal loan to or for any director, officer or employee.

SECURITY OWNERSHIP OF BENEFICIAL OWNERS AND MANAGEMENT

     The following table contains information provided to us by our directors and management, or contained in our share ownership records, with respect to beneficial ownership of our common shares as of September 30, 2005:

• each Named Executive Officer;

• each director; and

• all directors and executive officers as a group.

     Each person has sole voting and investment power with respect to the common shares listed.

	Shares Beneficially Owned
Name	Number		%
Mel F. Belich, Q.C.		2,344,616		1.84
Kim N. Davies, P.Geoph.		325,804		0.26
Marc R. Junghans, P.Geol.		20,224		0.02
Norman G. Knecht, C.A.		21,303		0.02
Irvine J. Koop, P. Eng.		459,000		0.36
Derek C. Longfield, P.Eng.		14,152		0.01
Tim G. Millar, LL.B.		152,934		0.12
John W. Preston		2,433,471		1.91
Ernie G. Sapieha, C.A.		6,744,618		5.30
Jeffrey T. Smith, P. Geol.		36,000		0.03
Murray J. Stodalka, P. Eng.		715,258		0.56
John A. Thomson, C.A.		25,000		0.02
All directors and executive officers as a group (12 persons)		13,292,380		10.45

10% Shareholder

     To our knowledge, the only person who beneficially owns, directly or indirectly, or exercises control or direction over more than 10% of the issued and outstanding common shares is 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. and Xandu Partners owns 18,845,400 common shares, representing approximately 14.81% of our outstanding common shares.

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DESCRIPTION OF MATERIAL INDEBTEDNESS AND OTHER COMMITMENTS

Senior Secured Credit Facilities

     As at September 30, 2005, we have a $264 million extendible revolving term credit facility with a Canadian chartered bank, as lead arranger and administrative agent for a syndicate of Canadian chartered bank lenders and a $10 million extendible revolving working capital facility, also with a Canadian chartered bank. The term credit facility is available for general corporate purposes and the working capital facility is available for ongoing working capital purposes. The senior secured credit facilities reach term on July 5, 2006 and mature 366 days later on July 6, 2007 at which time the facilities must be repaid in full. We have the right, and currently intend, to request that the term and maturity of our senior secured credit facilities be extended from time to time, in each case for a period of 364 days, subject to our bank lenders’ consenting to such requests. As of September 30, 2005, there was $260 million outstanding under the term credit facility and no amounts outstanding under the working capital facility.

     Under our senior secured credit facilities, the amount of our permitted borrowing base was initially established by, and is periodically redetermined by, the lenders. The borrowing base is set at the sole discretion of the lenders under the credit facilities and is based on their estimate of the lending value of our proved producing reserves and, to the extent the lenders determine in their sole discretion to include them, proved non-producing reserves or specified proved undeveloped reserves. As of the date of this short form prospectus, our borrowing base under our senior secured credit facilities is $345 million. On September 30, 2005, our authorized senior secured credit facilities were $274 million. We have recently increased these facilities to $289 million. Amounts outstanding under our senior secured credit facilities bear interest at a rate dependent on the type of accommodation provided, including Canadian 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. As of September 30, 2005, those rates were set at 0.15%, 1.15% and 1.15%, respectively.

     Our senior secured credit facilities have customary covenants including, but not limited to, covenants with respect to:

• creating additional liens or security interests;

• transferring or selling of assets;

• entering into mergers and amalgamations;

• incurring additional debt;

• providing additional guarantees; and

• entering into swaps and derivatives contracts.

     Our senior secured 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 Compton Finance, and which Compton Finance holds in Hornet Energy Ltd., and are guaranteed by each of our borrowing base subsidiaries, including Compton Finance. Our borrowing base subsidiaries will be Compton Finance, Compton Holdings, Compton Petroleum partnership and Hornet Energy Ltd. The guarantees are or will be secured by a fixed and floating charges and security interests on all of the undertakings, properties and assets of each of our borrowing base subsidiaries.

     Under the terms of our senior secured 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 secured 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 secured credit facilities.

Initial Notes due 2013

     On November 22, 2005, we issued and sold US$300 million aggregate principal amount of senior term notes, the Initial Notes, which bear interest semi-annually, in arrears on December 1, and June 1 of each year, at a rate of 7⁵/₈% per year with principal repayable on December 1, 2013. We intend to exchange the Initial Notes for the Exchange Notes. See “The Exchange Offer”.

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9.90% Notes due 2009

     In May 2002, we issued and sold US$165 million aggregate principal amount of senior term notes which bear interest semi-annually, in arrears on May 15 and November 15 of each year, at a rate of 9.90% per year, with principal repayable on May 15, 2009. On October 31, 2005, we commenced a tender offer for all of the 9.90% Notes, and as of November 14, 2005 (the “Consent Date”) 95.91% of the principal amount of the 9.90% Notes (US$158,250,000) had been tendered. On November 22, 2005, Compton Holdings, our wholly-owned subsidiary, purchased the 9.90% Notes that were tendered through the Consent Date. These 9.90% Notes will not be cancelled, but instead, will remain outstanding and will be held by Compton Holdings. The tender offer for the 9.90% Notes expired on November 29, 2005. We expect to redeem the US$6.75 million aggregate principal balance of 9.90% Notes not tendered in the tender offer on May 15, 2006.

Mazeppa Processing Partnership and Related Agreements

     The Mazeppa gas plant and related facilities and gathering systems are owned by Mazeppa Processing partnership, or MPP, an Alberta limited partnership. We do not have an ownership position in MPP. On August 18, 2004, we entered into a series of agreements whereby the MPP Limited Partner subscribed for the limited partnership interests of MPP.

     Processing Agreement.Pursuant to a processing agreement, MPP has agreed to process a majority of our southern Alberta natural gas at the Mazeppa facilities through April 30, 2009. At the end of the term of the processing agreement, we may request a renewal on terms to be based on the MPP Limited Partner’s refinancing and, to the extent reasonably appropriate, that incorporate the principles and methodology initially used in the processing agreement. Under the agreement, we pay to MPP a fixed base fee of $764,000 per month plus all operating costs of MPP, net of third party revenues. We are obligated to pay the fixed base fee every month regardless of the amount of our production processed by MPP. We are obligated to pay this fee and make other processing payments under this agreement under all circumstances, including damage or destruction to the facilities that delays, impedes or makes impossible the processing of our production, the bankruptcy or insolvency of MPP or the failure of MPP to process our production. On or before April 30 in each year, the MPP Limited Partner’s lenders make a determination of the amount and value of our dedicated proved reserves and if either fall below a predetermined amount we are obligated to make a “reserve risk payment” to MPP. Because of the continued growth of our dedicated reserves, we consider it unlikely that such reserve payment will be required during the term of the processing agreement.

     The MPP processing agreement includes a number of events in which we would be in default, including: (i) our failure to make required payments, (ii) a material regulatory change adversely affecting the operations of the Mazeppa facilities or our ability to produce our dedicated reserves; (iii) a material violation of environmental law that affects our dedicated reserves or the Mazeppa facilities or subjects MPP to any material liability; (iv) any material damage to the Mazeppa gas plant or related facilities; and (v) a change of control at Compton. Upon an event of default, MPP has a number of remedies. Under one of these remedies we would become obligated to pay, (i) all outstanding and unpaid fees under the processing agreement up to the date on which we are given notice by MPP of the default, including interest thereon; (ii) all liabilities and expenses incurred by the MPP Limited Partner in connection with the early repayment of its loan used to originally fund approximately $73.5 million of its subscription for $75 million of partnership units in MPP, including liabilities and expenses relating to the redeployment of the funds and early termination penalties plus an additional month’s base fee; and (iii) a stipulated amount decreasing from $75 million to $55 million by the end of the five-year term. Upon payment of the stipulated amount, the proceeds of which may be used to repay a portion or all of the amounts outstanding under the MPP Limited Partner’s loan, and payment of the other amounts described above, the processing agreement would terminate and we would become the owner of the Mazeppa gas plant and related facilities free of all prior MPP related encumbrances.

     Management Agreement.Pursuant to a management agreement, we control substantially all normal operating decisions with respect to the Mazeppa facilities and receive a monthly fee of $30,000 for these services. The management agreement has a term that expires on April 30, 2009 subject to sooner termination upon default and subject to replacement of Compton as manager upon a change of control at Compton or a material adverse change in our affairs. Under the management agreement, we must obtain and maintain specified insurance coverage for the Mazeppa facilities. The beneficiary of this insurance is MPP and the MPP Limited Partner. We have also agreed to indemnify MPP, MPP’s general partner, and the MPP Limited Partner and its lenders for any claims related to or arising out of or in connection with our operation of the Mazeppa facilities and for any costs, expenses or claims resulting from

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environmental activity or hazardous materials used in connection with the Mazeppa gas plant and related facilities during the term of the management agreement.

     Dedication, Production and Delivery Agreement.Pursuant to a dedication, production and delivery agreement, we have committed to process all of our natural gas production from our dedicated southern Alberta reserves at the Mazeppa gas plant and related facilities through April 30, 2019. As long as the processing agreement remains in effect, we are required to process our production from the dedicated reserves in accordance with the terms of that agreement. MPP may continue to require us to process the dedicated reserves exclusively at the Mazeppa facilities after expiry of the processing agreement. Further, for the term of the agreement, we may not sell any of the dedicated reserves if we would be left with less than an agreed upon amount of dedicated reserves without the prior consent of MPP or unless the purchaser of such reserves enters into a substantially similar dedication, production and delivery agreement with MPP. We have also agreed to indemnify MPP, MPP’s general partner, and the MPP Limited Partner and its lenders for any costs, expenses or claims resulting from environmental activity or hazardous materials used in connection with the Mazeppa gas plant and related facilities or the dedicated reserves for a term of 15 years, other than those claims arising by, through or under the acts of MPP after termination of the management agreement discussed above.

     Option Agreement.Pursuant to an option agreement, we have the option to purchase all of the MPP limited partnership units from the MPP Limited Partner at the end of the term of the MPP processing agreement for $55 million plus one month of base fees, any outstanding fees due under MPP processing agreement and the MPP Limited Partner’s costs. We also have the option to purchase the MPP limited partnership units from the MPP Limited Partner during the term of the MPP processing agreement for the unamortized balance of the stipulated amount (referred to above under “—Processing Agreement”) plus outstanding fees due under the MPP processing agreement and the MPP Limited Partner’s costs.

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THE EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

     On November 22, 2005, the Issuer sold its Initial Notes in a private placement exempt from the registration requirements of the Securities Act and pursuant to applicable prospectus exemptions under Canadian securities laws, and the Initial Purchasers then resold them in reliance on other exemptions from the registration requirements of the Securities Act and such prospectus exemptions. Consequently, the Initial Notes are subject to transfer restrictions under these securities laws. Pursuant to the terms of a Registration Rights Agreement entered into by the Issuer, the Guarantors and the Initial Purchasers on November 22, 2005, the Issuer and the Guarantors agreed, among other things, to deliver this short form prospectus, and to file an Exchange Offer Registration Statement with the SEC with respect to a proposed Exchange Offer to the holders of the Initial Notes who are not prohibited by law or policy of the SEC from participating in the Exchange Offer, to issue and deliver to such holders, in exchange for the Initial Notes, the Exchange Notes that would be registered under the Securities Act.

     The Issuer and the Guarantors agreed to keep the Exchange Offer Registration Statement effective for not less than 30 days (or longer if required by applicable law) after the date notice of the Exchange Offer is mailed to the holders of the Initial Notes. In addition, the Issuer and the Guarantors agreed in the event that (i) Compton Finance and the Guarantors determine that the Exchange Offer is not available or may not be consummated because it would violate applicable law or the applicable interpretations of the staff of the SEC, (ii) the Exchange Offer is not for any other reason completed by the 20^th day following the consummation of the Exchange Offer or (iii) the Exchange Offer has been completed and in the opinion of counsel for the Initial Purchasers an Exchange Offer Registration Statement must be filed and a prospectus must be delivered by the Initial Purchasers in connection with any offering or sale of the Exchange Notes, they shall use their commercially reasonable efforts to cause to be filed as soon as practicable after such determination, date or notice of such opinion of counsel is given to the Issuer and the Guarantors, as the case may be, a Shelf Registration Statement providing for the sale by the holders of all of the Exchange Notes and to have such Shelf Registration Statement declared effective by the SEC.

     If required by the terms of the Registration Rights Agreement, we will file with the SEC a Shelf Registration Statement to cover resales of the Initial Notes by the holders thereof who satisfy certain conditions relating to the provision of information in connection with the Shelf Registration Statement. We will use our reasonable best efforts to cause the applicable registration statement to be declared effective as promptly as possible by the SEC.

     A holder selling Initial Notes or Exchange Notes in the United States pursuant to a Shelf Registration Statement would be required to be named as a selling security holder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with these sales and will be bound by the applicable provisions of the Registration Rights Agreement (including certain indemnification obligations).

     Pursuant to the Registration Rights Agreement, we will be required to pay additional interest if a registration default exists at a rate equal to US$0.05 per week in principal amount of the Initial Notes for the first 90 day period immediately following occurrence of the registration default and will increase by an additional US$0.05 per week per US$1,000 in principal amount of Initial Notes with respect to each subsequent 90 day period until all registration defaults have been cured, up to a maximum of US$0.25 per week per US$1,000 principal amount of Initial Notes. A registration default will exist, among other things, if:

• we fail to file the Exchange Offer Registration Statement with the SEC on or prior to February 20, 2006;

• we fail to have the Exchange Offer Registration Statement declared effective by May 21, 2006;

• the Exchange Offer is not consummated within 45 days of the date the Exchange Offer Registration Statement is declared effective; or

• the Exchange Offer Registration Statement or the Shelf Registration Statement is declared effective but thereafter ceases to be effective or usable in connection with resales or exchanges of Initial Notes during the periods specified in the Registration Rights Agreement.

Following the cure of all registration defaults, the accrual of additional interest will cease.

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     We are conducting the Exchange Offer to satisfy our obligations under the Registration Rights Agreement. If you participate in the Exchange Offer, you will, with limited exceptions, receive Exchange Notes that are freely tradable and not subject to special interest or transfer restrictions. You should read the discussion under “— Resale of the Exchange Notes” for more information regarding your ability to transfer the Exchange Notes.

     The Exchange Offer is not being made to, nor will we accept tenders for exchange from, holders of Initial Notes in any jurisdiction in which the Exchange Offer or the acceptance of the Exchange Offer would not be in compliance with the securities laws or blue sky laws of such jurisdiction.

     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.”

Terms of the Exchange Offer

     We are offering, upon the terms and subject to the conditions set forth in this short form prospectus and the accompanying letter of transmittal, to exchange up to US$300,000,000 aggregate principal amount of the Exchange Notes for a like aggregate principal amount of outstanding Initial Notes. We will accept for exchange any and all Initial Notes that are properly tendered on or prior to 5 p.m., New York City time, on February 6, 2006, or such later time and date to which we extend the Exchange Offer. We will issue US$1,000 principal amount of the Exchange Notes in exchange for each US$1,000 principal amount of outstanding Initial Notes accepted in the Exchange Offer. You may tender some or all of your Initial Notes pursuant to the Exchange Offer; however, Initial Notes may be tendered only in integral multiples of US$1,000 in principal amount.

     As of the date of this short form prospectus, US$300,000,000 in aggregate principal amount of the Initial Notes were outstanding. This short form prospectus, together with the letter of transmittal, is being sent to all holders of the Initial Notes known to us. Our obligation to accept Initial Notes for exchange pursuant to the Exchange Offer is subject to certain conditions as set forth below under “— Conditions to the Exchange Offer.”

     The Exchange Agent will act as agent for the tendering holders for the purpose of receiving the Exchange Notes from us. If any tendered Initial Notes are not accepted for exchange because of an invalid tender or otherwise, certificates for the unaccepted Initial Notes will be returned, without expense, to the tendering holder as promptly as practicable after the expiration date. Holders of the Initial Notes do not have appraisal or dissenters’ rights under the laws of the State of New York or the indenture. We intend to conduct the Exchange Offer in accordance with the applicable requirements of Canadian securities laws, the Securities Act and the Exchange Act and the rules and regulations under the Securities Act and the Exchange Act.

     None of us, our boards of directors or our management recommends that you tender or not tender your Initial Notes in the Exchange Offer. In addition, no one has been authorized to make any such recommendation. You must make your own decision whether to participate in the Exchange Offer and, if you choose to participate, the aggregate principal amount of your Initial Notes to tender, after carefully reading this short form prospectus and the letter of transmittal. We urge you to consult your financial and tax advisors in making your decision on what action to take.

Conditions to the Exchange Offer

     You must tender your Initial Notes in accordance with the requirements of this short form prospectus and the letter of transmittal to participate in the Exchange Offer. Notwithstanding any other provision of the Exchange Offer, or any extension of the Exchange Offer, we are not required to accept for exchange any Initial Notes, and, we may terminate or amend the Exchange Offer, if we determine at any time prior to the expiration date, that the Exchange Offer violates applicable law or any applicable interpretation by the respective staffs of the SEC, Alberta Securities Commission or Ontario Securities Commission of applicable law.

     In addition, we will not be obligated to accept for exchange the Initial Notes of any holder that has not made to us:

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• the representations described under “— Procedures for Tendering Initial Notes — Representations Made by Tendering Holders of Initial Notes” and “Plan of Distribution;” and

• any other representations reasonably necessary under applicable SEC rules, regulations or interpretations to make available to us an appropriate form for registration of the Exchange Notes under the Securities Act.

     The foregoing conditions are for our sole benefit, and we may assert them regardless of the circumstances giving rise to any such condition, or we may waive the conditions, completely or partially, whenever or as many times as we may choose, in our sole discretion. Our failure at any time to exercise any of the above rights will not be a waiver of those rights, and each right will be deemed an ongoing right that may be asserted at any time. Any determination by us concerning the events described above will be final and binding upon all parties. If we determine that a waiver of conditions materially changes the Exchange Offer, this short form prospectus will be amended or supplemented, and the Exchange Offer extended, if appropriate, as described under “— Expiration Date; Extensions; Amendments.”

     In addition, at any time when any stop order is threatened or in effect with respect to the registration statement that includes this short form prospectus or with respect to the qualification of the indenture governing the Notes under the U.S. Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”), we will not accept for exchange any Initial Notes tendered, and no Exchange Notes will be issued in exchange for any such Initial Notes.

Expiration Date; Extensions; Amendments

     The expiration date of the Exchange Offer will be 5:00 p.m., New York City time, on February 6, 2006, unless we, in our sole discretion, extend the expiration date of the Exchange Offer. If we extend the expiration date of the Exchange Offer, the expiration date of the Exchange Offer will be the latest time and date to which the Exchange Offer is extended. We will notify the Exchange Agent by oral or written notice of any extension of the expiration date and make a public announcement of this extension no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

     In addition, we expressly reserve the right, at any time or from time to time, at our sole discretion:

• to delay the acceptance of the Initial Notes;

• to extend the Exchange Offer;

• if we determine any condition to the Exchange Offer has not occurred or has not been satisfied, to terminate the Exchange Offer; and

• to waive any condition or amend the terms of the Exchange Offer in any manner.

     If the Exchange Offer is amended in a manner we deem to constitute a material change, we will as promptly as practicable distribute to the registered holders of the Initial Notes a prospectus supplement that discloses the material change. If we take any of the actions described in the previous paragraph, we will as promptly as practicable give oral or written notice of this action to the Exchange Agent and will make a public announcement of this action.

     During any extension of the Exchange Offer, all Initial Notes previously tendered will remain subject to the Exchange Offer and may be accepted for exchange by us. Any Initial Notes not accepted for exchange for any reason will be returned without expense to the tendering holder as promptly as practicable after the expiration or termination of the Exchange Offer.

Procedures for Tendering Initial Notes

     Valid Tender

     The tender of a holder’s Initial Notes and our acceptance of those Initial Notes will constitute a binding agreement between the tendering holder and us upon the terms and subject to the conditions set forth in this short form prospectus and in the letter of transmittal. Except as set forth below, if you wish to tender Initial Notes pursuant to the Exchange Offer, you must, on or prior to the expiration date of the Exchange Offer:

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• transmit a properly completed and duly executed letter of transmittal, together with all other documents required by the letter of transmittal, to the Exchange Agent at one of the addresses set forth below under “— Exchange Agent;”

• arrange with DTC to cause an agent’s message to be transmitted with the required information (including a book-entry confirmation) to the Exchange Agent at one of the addresses set forth below under “— Exchange Agent;” or

• comply with the guaranteed delivery procedures described below.

     In addition, on or prior to the expiration date of the Exchange Offer:

• the Exchange Agent must receive the certificates for the Initial Notes, together with the properly completed and duly executed letter of transmittal;

• the Exchange Agent must receive a timely confirmation of a book-entry transfer of the Initial Notes being tendered into the Exchange Agent’s account at DTC, together with the properly completed and duly executed letter of transmittal or an agent’s message; or

• the holder must comply with the guaranteed delivery procedures described below.

     The letter of transmittal or agent’s message may be delivered by mail, facsimile, hand delivery or overnight carrier to the Exchange Agent.

     The term “agent’s message” means a message transmitted to the Exchange Agent by DTC that states that DTC has received an express acknowledgment from a tender holder that it agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this tendering holder. The agent’s message forms a part of book-entry transfer.

     If you beneficially own Initial Notes and those notes are registered in the name of a broker-dealer, commercial bank, trust company or other nominee or custodian, and you wish to tender your Initial Notes in the Exchange Offer, you should contact the registered holder as soon as possible and instruct it to tender the Initial Notes on your behalf and comply with the instructions set forth in this short form prospectus and the letter of transmittal.

     If you tender fewer than all of your Initial Notes, you should fill in the amount of the Initial Notes tendered in the appropriate box in the letter of transmittal. If you do not indicate the amount tendered in the appropriate box, we will assume you are tendering all Initial Notes that you hold.

     The method of delivery of the certificates for the Initial Notes, the letter of transmittal and all other documents is at your sole election and risk. Instead of delivery by mail, it is recommended that you use an overnight or hand delivery service. If delivery is by mail, it is recommended that you use registered mail, properly insured, with return receipt requested. In all cases, sufficient time should be allowed to assure timely delivery. No letters of transmittal or Initial Notes should be sent directly to us. Delivery is complete when the Exchange Agent actually receives the items to be delivered. Delivery of documents to DTC in accordance with DTC’ s procedures does not constitute delivery to the Exchange Agent.

     Signature Guarantees

     Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed unless the Initial Notes surrendered for exchange are tendered:

• by a registered holder of the Initial Notes who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal; or

• for the account of an eligible institution.

     An eligible institution is a firm or other entity that is a member 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 any other “eligible guarantor institution” as this term is defined in Rule 17Ad-15 under the Exchange Act.

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     If a signature on a letter of transmittal or a notice of withdrawal is required to be guaranteed, this guarantee must be by an eligible institution.

     If the letter of transmittal is signed by a person other than the registered holder of the Initial Notes, the Initial Notes surrendered for exchange must be endorsed by, or be accompanied by a written instrument of transfer or exchange, in form satisfactory to us in our sole discretion, duly executed by, the registered holder, with the signature guaranteed by an eligible institution.

     If the letter of transmittal is signed by a trustee, executor, administrator, guardian, attorney-in-fact, officer of a corporation or other person acting in a fiduciary or representative capacity, this person should sign in that capacity when signing. In addition, this person must submit to us, together with the letter of transmittal, evidence satisfactory to us in our sole discretion of his or her authority to act in this capacity, unless we waive this requirement.

     Book-Entry Transfer

     For tenders by book-entry transfer of Initial Notes cleared through DTC, the Exchange Agent will make a request to establish an account at DTC with respect to the Initial Notes for purposes of the Exchange Offer. Any financial institution that is a DTC participant may make book-entry delivery of Initial Notes by causing DTC to transfer the Initial Notes into the Exchange Agent’s account at DTC in accordance with DTC’s procedures for transfer. We understand that any financial institution that is a participant in DTC may use the Automated Tender Offer Program procedures to tender Initial Notes pursuant to the Exchange Offer. Accordingly, any DTC participant may make book-entry delivery of the Initial Notes by causing DTC to transfer those Initial Notes into the Exchange Agent’s account in accordance with DTC’s Automated Tender Offer Program procedures for transfer.

     Although delivery of the Initial Notes pursuant to the Exchange Offer may be effected through book-entry transfer at DTC, you will not have validly tendered your Initial Notes pursuant to the Exchange Offer until, on or prior to the expiration date, either:

• the properly completed and duly executed letter of transmittal, or an agent’s message, together with any required signature guarantees and any other required documents, has been transmitted to and received by the Exchange Agent at one of the addresses set forth below under “— Exchange Agent;” or

• the guaranteed delivery procedures described below have been complied with.

     Guaranteed Delivery Procedures

     If you wish to tender your Initial Notes and:

• your Initial Notes are not immediately available;

• time will not permit your Initial Notes or other required documents to reach the Exchange Agent before the expiration date; or

• you cannot complete the procedure for book-entry transfer on a timely basis,

     you may tender your Initial Notes according to the guaranteed delivery procedures described in the letter of transmittal. Those procedures require that:

• tender be made by and through an eligible institution;

• on or prior to the expiration date of the Exchange Offer, the Exchange Agent receives from this eligible institution a properly completed and duly executed letter of transmittal, or an agent’s message, with any required signature guarantees, and a properly completed and duly executed notice of guaranteed delivery, substantially in the form provided:

• setting forth the name and address of the holder of the Initial Notes being tendered,

• stating that the tender is being made, and

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• guaranteeing that within three NYSE trading days after the date of execution of the notice of guaranteed delivery, the certificates for all physically tendered Initial Notes, in proper form for transfer, or a book-entry confirmation, and any other documents required by the letter of transmittal, will be deposited by the eligible institution with the Exchange Agent; and

• the Exchange Agent receives the certificates for the Initial Notes, in proper form for transfer, or a book-entry confirmation, and all other documents required by the letter of transmittal, are received by the Exchange Agent within three NYSE trading days after the date of execution of the notice of guaranteed delivery.

     If you wish to tender your Initial Notes pursuant to the guaranteed delivery procedures, you must ensure that the Exchange Agent receives a properly completed and duly executed letter of transmittal, or agent’s message, and notice of guaranteed delivery before the expiration date of the Exchange Offer.

     Determination of Validity of Tender

     We will resolve in our sole discretion all questions as to the validity, form, eligibility (including time of receipt) and acceptance of any Initial Notes tendered for exchange. Our determination of these questions and our interpretation of the terms and conditions of the Exchange Offer, including without limitation the letter of transmittal and its instructions, shall be final and binding on all parties. A tender of Initial Notes is invalid until all defects and irregularities have been cured or waived. Each holder must cure any and all defects or irregularities in connection with his, her or its tender of Initial Notes within the reasonable period of time determined by us, unless we waive these defects or irregularities. None of us, our affiliates and assigns, the Exchange Agent and any other person is under any duty or obligation to give notice of any defect or irregularity with respect to any tender of the Initial Notes, and none of them shall incur any liability for failure to give any such notice.

     We reserve the absolute right in our sole and absolute discretion to:

• reject any and all tenders of Initial Notes determined to be in improper form or unlawful;

• waive any condition of the Exchange Offer; and

• waive any condition, defect or irregularity in the tender of Initial Notes by any holder, whether or not we waive similar conditions, defects or irregularities in the case of other holders.

     Representations Made by Tendering Holders of Initial Notes

     By tendering Initial Notes, you represent to us that, among other things:

• you are acquiring the Exchange Notes in the ordinary course of business;

• you do not have any arrangement or understanding with any person or entity to participate in the distribution of the Exchange Notes;

• if you are not a broker-dealer, you are not engaged in and do not intend to engage in a distribution of the Exchange Notes;

• if you are a broker-dealer that will receive Exchange Notes for your own account in exchange for Initial Notes that were acquired by you as a result of market-making activities or other trading activities, you will deliver a prospectus, as required by law, in connection with any resale of the Exchange Notes (see “Plan of Distribution”); and

• you are not our “affiliate” as defined in Rule 405 of the Securities Act.

     If you are our “affiliate,” as defined under Rule 405 of the Securities Act, or are engaged in or intend to engage in or have an arrangement or understanding with any person to participate in a distribution of the Exchange Notes, you will represent and warrant that you (i) may not rely on the applicable interpretations of the staff of the SEC and (ii) must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. The letter of transmittal states that by so acknowledging 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.

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     In addition, in tendering Initial Notes, you must warrant in the letter of transmittal or in an agent’s message that:

• you have full power and authority to tender, exchange, sell, assign and transfer Initial Notes;

• we will acquire good, marketable and unencumbered title to the tendered Initial Notes, free and clear of all liens, restrictions, charges and other encumbrances; and

• the Initial Notes tendered for exchange are not subject to any adverse claims or proxies.

     You must also warrant and agree that you will, upon request, execute and deliver any additional documents requested by us or the Exchange Agent to complete the exchange, sale, assignment and transfer of the Initial Notes.

     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.”

Acceptance of Initial Notes; Delivery of Exchange Notes

     Upon satisfaction or waiver of all of the conditions to the Exchange Offer, we will accept all Initial Notes validly tendered, and not withdrawn, on or prior to the expiration date of the Exchange Offer. We will issue the Exchange Notes to the Exchange Agent as promptly as practicable after acceptance of the Initial Notes. See “— Terms of the Exchange Offer.”

     For purposes of the Exchange Offer, we shall be deemed to have accepted validly tendered Initial Notes for exchange when, as and if we have given oral or written notice of our acceptance to the Exchange Agent, with written confirmation of any oral notice to be given promptly thereafter.

Withdrawal Rights

     You may withdraw tenders of your Initial Notes at any time prior to the expiration date of the Exchange Offer.

     For a withdrawal to be effective, the Exchange Agent must receive a written notice of withdrawal from you. A notice of withdrawal must:

• specify the name of the person tendering the Initial Notes to be withdrawn;

• identify the Initial Notes to be withdrawn, including the total principal amount of these Initial Notes; and

• where certificates for the Initial Notes have been transmitted, specify the name of the registered holder of the Initial Notes, if different from the person withdrawing the tender of these Initial Notes.

     If you delivered or otherwise identified certificates representing Initial Notes to the Exchange Agent, then you must also submit the serial numbers of the particular certificates to be withdrawn and, unless you are an eligible institution, the signature on the notice of withdrawal must be guaranteed by an eligible institution. If you tendered Initial Notes as a book-entry transfer, your notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn Initial Notes and otherwise comply with the procedures of DTC. You may not withdraw or rescind any notice of withdrawal; however, Initial Notes properly withdrawn may again be tendered at any time on or prior to the expiration date of the Exchange Offer.

     We will determine, in our sole discretion, all questions as to the validity, form and eligibility (including time of receipt) of any and all notices of withdrawal, and our determination of these questions shall be final and binding on all parties. Any Initial Notes properly withdrawn will be deemed not to have been validly tendered for exchange for purposes of the Exchange Offer and will be returned to the holder without cost as soon as practicable after their withdrawal.

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Exchange Agent

     The Bank of Nova Scotia Trust Company of New York is the Exchange Agent for the Exchange Offer. You should direct all tendered Initial Notes, executed letters of transmittal and other related documents to the Exchange Agent. You should direct all questions and requests for assistance, requests for additional copies of this short form prospectus or of the letter of transmittal and requests for notices of guaranteed delivery to the Exchange Agent at the following address and telephone numbers:

By Mail, Hand or
Overnight Delivery:	By Facsimile for
The Bank of Nova Scotia Trust Company of New York	Eligible Institutions:
One Liberty Plaza, 23rd Floor	(212) 225-5427
New York, NY 10006	Confirmation by Telephone:
Attention: Pat Keane	(212) 225-5427

     If you deliver executed letters of transmittal and any other required documents to an address or facsimile number other than those set forth above, your tender is invalid.

Fees and Expenses

     We will bear the expenses of soliciting Initial Notes for exchange. The principal solicitation is being made by mail by the Exchange Agent. Additional solicitations may be made by facsimile, telephone or in person by our officers, directors and regular employees.

     We have not retained any dealer-manager in connection with the Exchange Offer and will not make any payments to any broker, dealer, nominee or other person, other than the Exchange Agent, for soliciting tenders of the Initial Notes pursuant to the Exchange Offer. We will pay the Exchange Agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

     We will pay the cash expenses to be incurred in connection with the Exchange Offer. They include:

• registration and filing fees;

• fees and expenses of the Exchange Agent and trustee; and

• accounting and legal fees and printing costs.

Your Failure to Participate in the Exchange Offer will Have Adverse Consequences

     Following the consummation of the Exchange Offer, we will have fulfilled most of our obligations under the Registration Rights Agreement. Unless you are an Initial Purchaser or a holder of Initial Notes who is prohibited by applicable law or SEC policy from participating in the Exchange Offer or who may not resell the Exchange Notes acquired in the Exchange Offer without delivering a prospectus and this short form prospectus is not appropriate or available for such resales by you, if you do not tender your Initial Notes in the Exchange Offer or if we do not accept your Initial Notes because you did not tender them properly, you will not have any further registration rights with respect to your Initial Notes, and you will not have the right to receive any special interest on your Initial Notes. In addition, your Initial Notes will continue to be subject to restrictions on their transfer. In general, any Initial Notes that are not exchanged for Exchange Notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act, applicable state securities laws and applicable Canadian securities laws.

     We may in the future seek to acquire unexchanged Initial Notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans, however, to acquire any unexchanged Initial Notes or to file with the SEC a shelf registration statement to permit resales of any unexchanged Initial Notes.

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Resale of the Exchange Notes

     Based on interpretations by the SEC staff set forth in no-action letters issued to third parties in similar transactions, such as Exxon Capital Holding Corporation and Morgan Stanley & Co. Incorporated, we believe that a holder of the Exchange Notes may offer the Exchange Notes for resale or resell or otherwise transfer the Exchange Notes in the United States without compliance with the registration and prospectus delivery requirements of the Securities Act, unless this holder:

• is our “affiliate” within the meaning of Rule 405 under the Securities Act;

• is a broker-dealer who purchased Initial Notes directly from us for resale under Rule 144A or any other available exemption under the Securities Act;

• acquired the Exchange Notes other than in the ordinary course of this holder’s business; or

• is participating, intends to participate or has an arrangement or understanding with any person to participate in the distribution of the Exchange Notes.

     Accordingly, holders of Initial Notes wishing to participate in the Exchange Offer must make the applicable representations described in “— Procedures for Tendering Initial Notes — Representations Made by Tendering Holders of Initial Notes” above.

     Although we are making the Exchange Offer in reliance on the interpretations by the SEC staff set forth in these no-action letters, we do not intend to seek our own no-action letter from the SEC. Consequently, we cannot assure you that the SEC staff would make a similar determination with respect to the Exchange Offer as it did in its no-action letters to third parties. If this interpretation is inapplicable and you resell or otherwise transfer any Exchange Notes without complying with the registration and prospectus delivery requirements of the Securities Act, you may incur liability under the Securities Act. We do not assume or indemnify you against this liability.

     You may not rely on the interpretations of the SEC staff in the above-described no-action letters if you are a holder of Initial Notes who:

• is our “affiliate” as defined in Rule 405 under the Securities Act;

• does not acquire the Exchange Notes in the ordinary course of business;

• tenders in the Exchange Offer with the intention to participate, or for the purpose of participating, in a distribution of the Exchange Notes; or

• is a broker-dealer that purchased Initial Notes from us to resell them pursuant to Rule 144A under the Securities Act or any other available exemption under the Securities Act, and

in the absence of an exemption, you must comply with the registration and prospectus delivery requirements of the Securities Act or applicable Canadian securities laws in connection with any resale or other transfer of the Exchange Notes.

     In addition, each broker-dealer that receives Exchange Notes for its own account in exchange for Initial Notes that were acquired by it 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 those Exchange Notes (see “Plan of Distribution”). Under the Registration Rights Agreement, we will be required to use our best efforts to keep the registration statement that includes this short form prospectus effective to allow these participating broker-dealers and other persons, if any, with similar prospectus delivery requirements to use this short form prospectus in connection with the resale of the Exchange Notes for the period that ends on the sooner of 180 days after the effectiveness of the registration statement that includes this short form prospectus and the date on which participating broker-dealers are no longer required to deliver a prospectus in connection with market-making or other trading activities.

     In order to comply with state securities laws, the Exchange Notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification is available and is complied with.

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     The Exchange Notes are not being offered for sale and may not be offered or sold, directly or indirectly in Canada, or to any resident thereof, except in accordance with the securities laws of the provinces and territories of Canada. We are not required, and do not intend, to qualify by prospectus in Canada the Exchange Notes, and accordingly the Exchange Notes will be subject to applicable restrictions on resale in Canada.

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DESCRIPTION OF THE NOTES

     You can find the definitions of certain terms used in this description under the subheading “Certain Definitions”. In this description, the word “Compton” refers only to Compton Petroleum Corporation and not to any of its Subsidiaries, the word “Issuer” refers only to Compton Petroleum Finance Corporation and not to any of its Subsidiaries and the word “Notes” refers to the 7⁵/₈% Senior Notes due 2013 of the Issuer guaranteed by Compton and its Restricted Subsidiaries (except the Issuer), and includes the Initial Notes and the Exchange Notes.

     The Issuer issued the Initial Notes under an indenture (the “indenture”), dated as of November 22, 2005, among the Issuer, Compton, as Parent Guarantor, the Initial Subsidiary Guarantors, as guarantors, and The Bank of Nova Scotia Trust Company of New York, as trustee. 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.

     The following description is a summary of the material provisions of the indenture but does not restate the indenture in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the Notes. Copies of the indenture are available as set forth below under “— Additional Information”. Certain defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture. References to “US$” are to United States dollars and to”$” and “Cdn$” are to Canadian dollars.

     The registered holder of a note (a “Holder”) will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture.

Brief Description of the Notes and the Guarantees

     The Notes

     The Notes:

• are general unsecured obligations of the Issuer;

• are equal in right of payment to all existing and future unsecured senior Indebtedness of the Issuer;

• are senior in right of payment with any permitted future subordinated Indebtedness of the Issuer;

• are unconditionally guaranteed by the Guarantors; and

• are effectively subordinated to all secured Indebtedness of the Issuer, Compton and the Subsidiary Guarantors, including the Credit Facilities which are secured by substantially all of the assets of the Issuer, Compton and the Subsidiary Guarantors.

     Assuming the initial offering of the Initial Notes had been completed as of September 30, 2005, and that the net proceeds had been applied as described under “Use of Proceeds,” the Issuer would have had $484 million of senior Indebtedness (including the Notes and excluding intercompany Indebtedness), of which $128 million would have been secured Indebtedness under the Credit Agreement.

     The Guarantees

     The Notes will be guaranteed on an unsecured unsubordinated basis (the “Subsidiary Guarantees”) by all of Compton’s Restricted Subsidiaries existing on the Issue Date (except the Issuer) and by all of Compton’s future Restricted Subsidiaries (collectively, the “Subsidiary Guarantors”). Compton will fully and unconditionally guarantee all obligations of the Issuer under the Notes and all obligations of each Subsidiary Guarantor under its Subsidiary Guarantee (the “Parent Guarantee” and, together with the Subsidiary Guarantees, the “Guarantees”). The Subsidiary Guarantors and Compton are referred to collectively as the “Guarantors.”

     Each Guarantee:

• is a general senior unsecured obligation of the Guarantor;

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• is equal in right of payment to all existing and future unsecured senior Indebtedness of that Guarantor; and

• is senior in right of payment with any permitted future senior subordinated Indebtedness of that Guarantor.

     Assuming the initial offering of the Initial Notes had been completed as of September 30, 2005, and that the net proceeds had been applied as described under “Use of Proceeds”, Compton and the Initial Subsidiary Guarantors would have had $484 million of senior Indebtedness (including the Guarantees and excluding intercompany Indebtedness), of which $128 million would have been secured Indebtedness under the Credit Agreement.

     As of the date of the indenture, all of Compton’s Subsidiaries, including the Issuer, will be “Restricted Subsidiaries” except Compton Petroleum (U.S.A.) Corporation and Redwood Energy (U.S.A.) Ltd. (the “Initial Unrestricted Subsidiaries”). These Initial Unrestricted Subsidiaries together accounted for less than 1% of our total assets, revenue and net earnings, respectively, for each of the year ended December 31, 2004 and the nine months ended September 30, 2005. Under the circumstances described below under the caption “— Certain Covenants — Designation of Unrestricted and Restricted Subsidiaries”, we will be permitted to designate certain of Compton’s other Subsidiaries as “Unrestricted Subsidiaries”. Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture and will not guarantee the Notes.

Principal, Maturity and Interest

     The Issuer may issue an unlimited principal amount of Notes under the indenture, but is initially limited to US$300 million aggregate principal amount. The Issuer may issue additional Notes from time to time after the 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 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. The Issuer will issue Notes in denominations of US$1,000 and integral multiples of US$1,000. The Notes will mature on December 1, 2013.

     Interest on the Notes will accrue at the rate of 7⁵/₈% per annum and will be payable semi-annually in arrears on June 1 and December 1, commencing on June 1, 2006. The Issuer will make each interest payment to the holders of record on the immediately preceding May 15 and November 15.

     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 the Issuer in writing, the Issuer 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 the Issuer 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. The Issuer may change the paying agent or registrar without prior notice to the Holders, and Compton or any of its Subsidiaries may act as paying agent or registrar.

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. The Issuer is not required to transfer or exchange any note selected for redemption. Also, the Issuer is not required to transfer or exchange any note for a period of 15 days before a selection of Notes to be redeemed.

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Subsidiary Guarantees

     The Notes will be guaranteed by the Initial Subsidiary Guarantors and by all of Compton’s future Restricted Subsidiaries. The Subsidiary Guarantees will be joint and several unsecured obligations of the Subsidiary Guarantors. The obligations of each Subsidiary 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 —Risks Related to the Notes —Federal, provincial and state statutes allow courts, under specific circumstances, to void subsidiary guarantees and require note holders to return payments received from guarantors”.

     A Subsidiary 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 Subsidiary Guarantor is the surviving Person), another Person, other than the Issuer or Compton or another Subsidiary Guarantor, unless:

(5)	immediately after giving effect to that transaction, no Default or Event of Default exists; and
(6)	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 Subsidiary 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 Subsidiary Guarantor will be released:

(1)	in connection with any sale of more than 50% of the Capital Stock of a Subsidiary 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 covenant described below under the caption “—Repurchase at the Option of Holders—Asset Sales; or
(2)	if Compton designates any Restricted Subsidiary that is a Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture.

Parent Guarantee

     Compton will fully and unconditionally guarantee on an unsecured unsubordinated basis all obligations of the Issuer under the Notes and all obligations of the Subsidiary Guarantors under the Subsidiary Guarantees.

Optional Redemption

     At any time prior to December 1, 2008, the Issuer 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 107.625% of the principal amount, plus accrued 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 the Issuer or Compton or any of Compton’s other Subsidiaries); and
(2)	the redemption occurs within 90 days of the date of the closing of such Equity Offering.

     If the Issuer 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, the Issuer may, at its option, redeem the Notes, in whole but not in part, upon not less than 30 nor more than 60 days’

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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 the Issuer’s option prior to December 1, 2009.

     On or after December 1, 2009, the Issuer 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 December 1 of the years indicated below:

Year	Percentage
2009		103.813	%
2010		101.906	%
2011 and thereafter		100.000	%

     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
(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 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 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.

Mandatory Redemption

     The Issuer is not required to make mandatory redemption or sinking fund payments with respect to the Notes.

Repurchase at the Option of Holders

     Change of Control

     If a Change of Control occurs, each Holder will have the right to require the Issuer to repurchase all or any part (equal to US$1,000 or an integral multiple thereof) of that Holder’s Notes pursuant to an offer (a “Change of Control Offer”) on the terms set forth in the indenture. In the Change of Control Offer, the Issuer will offer a 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 repurchase (the “Change of Control Payment”). Within 30 days following any Change of Control, the Issuer will be required by the indenture to mail a notice to each Holder (excluding Compton or any of its Restricted Subsidiaries) describing the transaction or transactions that constitute the Change of Control and offering to repurchase Notes on the date specified in the notice (the “Change of Control Payment Date”), 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. The Issuer will be required by the indenture to comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations

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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, the Issuer will be required by the indenture to 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.

     On the Change of Control Payment Date, the Issuer or its designated agent will, to the extent lawful:

(1)	accept for payment all Notes or parts 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 parts 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 parts of Notes being purchased by the Issuer.

     The depositary or the paying agent will promptly mail to each Holder 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 thateach new note will be in a principal amount of US$1,000 or an integral multiple of US$1,000.

     The Issuer 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 Credit Agreement will prohibit the Issuer or any of the Guarantors from repurchasing any Notes prior to their scheduled maturity date, including pursuant to a Change of Control Offer, and will also provide that a Change of Control Offer (as well as certain other change of control events with respect to Compton and any change that results in a Restricted Subsidiary that is a guarantor under the Credit Agreement not being wholly-owned by Compton) would constitute an event of default under the Credit Agreement. Any future credit agreements or other similar agreements to which the Issuer or any Guarantor becomes a party may contain similar restrictions and provisions. If a Change of Control occurs at a time when the Issuer or any Guarantor is prohibited from purchasing Notes, it could seek the consent of its lenders to the purchase of Notes or could attempt to refinance the borrowings that provide for such prohibition. If it does not obtain such a consent or repay such borrowings, the Issuer will remain prohibited from purchasing Notes. In such case, the Issuer’s failure to purchase tendered Notes would constitute an Event of Default under the indenture which would, in turn, constitute an event of default under such other agreements. In addition, the exercise by the Holders of their right to require the Issuer to repurchase the Notes upon a Change of Control could cause an event of default under these other agreements, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Issuer. Finally, the Issuer’s ability to pay cash to the Holders upon a repurchase of their Notes may be limited by the Issuer ‘s then existing financial resources.

     The provisions described above that require the Issuer 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 to require that the Issuer repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction.

     The Issuer 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 the Issuer 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 to require the Issuer to repurchase its Notes as a result of a sale, lease, transfer, conveyance or other disposition of less

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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, rights or Equity Interests of a Subsidiary of Compton 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 or a combination thereof. 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, liabilities that are by their terms subordinated to the Notes or any Guarantee and liabilities to the extent owed to Compton or any Restricted Subsidiary of Compton) 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

(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 secured Indebtedness, and Obligations in respect thereof, of Compton or any Restricted Subsidiary of Compton, including secured Indebtedness and Obligations under any Credit Facility, other than Indebtedness or other Obligations that are 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 (or enter into a legally binding agreement to purchase such assets or Voting Stock within 90 days after the date of such binding agreement;provided, however, that if any such legally binding agreement to invest such Net Proceeds is terminated, then Compton or the applicable Restricted Subsidiary may within 30 days of such termination or 365 days after the receipt of any Net Proceeds from the applicable Asset Sale, whichever is later, invest such Net Proceeds as provided in clause (1), (3) or (4) hereof or to acquire all or substantially all of the assets of, or a majority of the Voting Stock of, another Oil and Gas Business;provided, further, that, if the Net Proceeds are not so applied within that time period, they will immediately be deemed to be Excess Proceeds (as defined below);
(3)	to make a capital expenditure; or
(4)	to acquire Permitted Assets.

Pending the final application of any Net Proceeds, Compton or such Restricted Subsidiary 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$20.0 million, the Issuer will be required by the indenture to make an offer (an “Asset Sale Offer”) to all Holders (excluding Compton or any of its Restricted Subsidiaries) and all holders (excluding Compton or any of its Restricted Subsidiaries) of other

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Indebtedness that ispari passuwith 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 otherpari passuIndebtedness 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 or any of its Restricted Subsidiaries may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of Notes and otherpari passuIndebtedness tendered into such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the Notes and such otherpari 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.

     The Issuer will be required by the Indenture to 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 Offer provisions of the indenture, the Issuer will be required by the Indenture to comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale Offer provisions of the indenture by virtue of such conflict.

     The Credit Agreement will prohibit the Issuer or any of the Guarantors from repurchasing any Notes prior to their scheduled maturity date, including pursuant to an Asset Sale Offer, and will also provide that certain asset sale events with respect to the Issuer or a Guarantor would constitute an event of default under the Credit Agreement. Any future credit agreements or other similar agreements to which the Issuer or any Guarantor becomes a party may contain similar restrictions and provisions. In the event an Asset Sale occurs at a time when the Issuer or any Guarantor is prohibited from purchasing Notes, it could seek the consent of its lenders to the purchase of Notes or could attempt to refinance the borrowings that contain such prohibition. If it does not obtain such a consent or repay such borrowings, the Issuer will remain prohibited from purchasing Notes. In such case, the Issuer’s failure to purchase tendered Notes would constitute an Event of Default under the indenture which would, in turn, constitute a an event of default under such other agreements. In addition, the exercise by the Holders of their right to require the Issuer to repurchase the Notes upon an Asset Sale could cause an event of default under these other agreements, even if the Asset Sale itself does not, due to the financial effect of such repurchase on Compton or the Issuer, as applicable. Finally, the Issuer’s ability to pay cash to the Holders upon a repurchase of their Notes may be limited by the Issuer ‘s then existing financial resources.

Certain Covenants

     Set forth below are certain covenants that are contained in the indenture.

     Covenant Suspension

     During any period of time that (a) the Notes have Investment Grade Ratings from both Rating Agencies and (b) no Default or Event of Default has occurred and is continuing under the indenture, Compton and the Restricted Subsidiaries will not be subject to:

(1) the provisions of the indenture described under “ – Repurchase at the Option of the Holders Change of Control” and “ -Asset Sales” and the following captions of this “—Certain Covenants” subheading:

(a)	“ -Restricted Payments” (except to the extent applicable under the provisions described below under “— Designation of Unrestricted and Restricted Subsidiaries”);
(b)	“ – Incurrence of Indebtedness and Issuance of Preferred Shares;”
(c)	“ –Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries”;
(d)	“ –Transactions with Affiliates;” and
(e)	clause (4) of “Amalgamation, Merger, Consolidation or Sale of Assets;” and

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(2) clauses (3) and (4) under the subheading “Events of Default and Remedies” to the extent that such clause applies to the covenants described in clause (1) above.

     If Compton and its Restricted Subsidiaries are not subject to these covenants for any period of time as a result of the previous sentence (a “Fall-Away Period”) and, subsequently, one, or both, of the Rating Agencies withdraws or downgrades its ratings assigned to the Notes below the required Investment Grade Ratings or an Event of Default (other than with respect to a suspended covenant) occurs and is continuing, then Compton and its Restricted Subsidiaries will thereafter again be subject to these covenants. The ability of Compton and its Restricted Subsidiaries to make Restricted Payments (as defined under the caption “—Restricted Payments” below) after the time of such withdrawal, downgrade or Event of Default will be calculated as if the covenant governing Restricted Payments had been in effect during the entire period of time from the Issue Date. Notwithstanding the foregoing, the continued existence after the end of the Fall-Away Period of facts and circumstances or obligations arising from transactions which occurred during a Fall-Away Period shall not constitute a breach of any covenant set forth in the indenture or cause a Default or an Event of Default thereunder;provided that:

(1) Compton and its Restricted Subsidiaries did not Incur or otherwise cause such facts and circumstances or obligations to exist in anticipation of:

(a)	a ratings withdrawal or downgrade below an Investment Grade Rating; or
(b)	an Event of Default; and

(2) Compton and its Restricted Subsidiaries did not reasonably believe that such transactions would result in such withdrawal or downgrade or Event of Default.

     Restricted Payments

     Compton will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1)	declare or pay (without duplication) any dividend or make any other payment or distribution on account of Compton’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment on account of such Equity Interests in connection with any merger or consolidation involving Compton or any of its Restricted Subsidiaries) or to the direct or indirect holders of Compton’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends, payments or distributions (x) payable in Equity Interests (other than Disqualified Stock) of Compton or (y) to Compton or a Restricted Subsidiary 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 or any of its Restricted Subsidiaries), in whole or in part, any Equity Interests of Compton or any Restricted Subsidiary thereof held by Persons other than Compton or any of its Restricted Subsidiaries;
(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 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;
(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

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	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 Issue Date (excluding Restricted Payments permitted by clauses (2), (3), (4) and (7) 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 Issue Date falls 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 Issue Date (i) as a contribution to its common equity capital or from the issue or sale of Equity Interests of Compton (other than Disqualified Stock) or (ii) 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, in the case of both clauses (i) and (ii), Equity Interests issued or sold to, or Disqualified Stock or debt securities held by, a Subsidiary of Compton or Equity Interests issued or sold to an employee stock option plan or a trust established by Compton or its Subsidiaries for the benefit of their employees),plus
(c)	with respect to Restricted Investments made by Compton and its Restricted Subsidiaries after the Issue Date, an amount equal to the net reduction in such Restricted Investments in any Person resulting from repayments of loans or advances, or other transfers of assets, in each case to Compton or any Restricted Subsidiary or from the net cash proceeds from the sale of any such Restricted Investment (except, in each case, to the extent any such payment or proceeds are included in the calculation of Consolidated Net Income), from the release of any guarantee (except to the extent any amounts are paid under such guarantee) or from redesignations of Unrestricted Subsidiaries (other than Initial Unrestricted Subsidiaries) as Restricted Subsidiaries, not to exceed, in each case, the amount of Restricted Investments previously made by Compton or any Restricted Subsidiary in such Person or Unrestricted Subsidiary after the Issue Date.

     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 (including premium, if any, and accrued interest thereon) of the Issuer, Compton or any Subsidiary Guarantor or of any Equity Interests of Compton or any Restricted Subsidiary in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Subsidiary of Compton) of, Equity Interests of Compton (other than Disqualified Stock);provided thatthe 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 Indebtedness of the Issuer that is subordinated to the Notes, or Indebtedness of Compton or any Guarantor that is subordinated to such Person’s Guarantee, in each case, with the net cash proceeds from an Incurrence of Permitted Refinancing Indebtedness;

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(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$5.0 million in any calendar year;
(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”;
(6)	the making of Restricted Payments, not otherwise provided for in any other clause of this paragraph, in an aggregate amount not to exceed US$25.0 million since the date of the indenture;
(7)	the payment of any dividend or distribution by a Restricted Subsidiary (other than the Issuer) of Compton to the holders of its Capital Stock (other than Disqualified Stock) on a pro rata basis;
(8)	any payment on subordinated Indebtedness between or among the Issuer and/or any of the Guarantors which Indebtedness was permitted to be Incurred under clause (6) under the caption “Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”; and
(9)	payments or distributions to dissenting shareholders pursuant to applicable law, pursuant to or in connection with a consolidation, amalgamation, merger or transfer of assets of Compton that complies with the provisions of the indenture applicable to mergers, consolidations, amalgamations and transfers of all or substantially all of the assets of Compton.

     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 case may be, pursuant to the Restricted Payment.

     Incurrence of Indebtedness and Issuance of Preferred Stock

     Compton will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness (including Acquired Debt), and the Issuer and Compton will not issue any preferred stock or Disqualified Stock, respectively, and Compton 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 preferred stock or Disqualified Stock, and the Issuer and the Subsidiary Guarantors may Incur Indebtedness or issue preferred stock or Disqualified 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 or preferred 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 Indebtedness by the Issuer or any of the Guarantors under or in respect of (collectively, “Permitted Debt”):

(1) Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) (with letters of credit and letters of guarantee 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$345 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 Issue Date to permanently repay any term Indebtedness under a Credit Facility pursuant to the covenant described

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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 Issue Date 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$150 million plus 25% of Adjusted Consolidated Net Tangible Assets as of the last day of the fiscal quarter for which internal financial statements are available immediately preceding the date on which such Indebtedness is Incurred;

(2)	Existing Indebtedness (other than Indebtedness described under clause (1), (3) or (6) of this paragraph);
(3)	the Initial Notes and the related Guarantees issued on the Issue Date and the Exchange Notes and the related Guarantees issued pursuant to the Registration Rights Agreement;
(4)	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 the Issuer 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$25.0 million at any time outstanding;
(5)	Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to refund, refinance or replace Indebtedness (other than 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)	intercompany Indebtedness between or among Compton and any of its Restricted Subsidiaries, including the intercompany Indebtedness referred to in the last sentence of the definition of “Existing Indebtedness”;provided, however, that:

(a)

if the Issuer or any Guarantor is the obligor on such Indebtedness, such Indebtedness must be unsecured and, except for the Acquired 9.90% Notes, expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Notes, in the case of the Issuer, or the Guarantee, in the case of a Guarantor; 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)	Hedging Obligations,providedthat such Hedging Obligations were Incurred in the ordinary course of business and not for speculative purposes;
(8)	the guarantee by the Issuer or any of the Guarantors of Indebtedness of Compton or the Issuer or another 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

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	purposes of this covenant;provided, in each such case, that the amount thereof is included in Fixed Charges of Compton as accrued;
(10)	Indebtedness and Obligations under Oil and Gas Hedging Contracts,providedthat 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)	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);
(13)	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$30.0 million;
(14)	Indebtedness of Compton or the Issuer to the extent that the net proceeds thereof are promptly (A) used to purchase Notes tendered in a Change of Control Offer or (B) deposited to defease or to satisfy and discharge the Notes; and
(15)	Indebtedness arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business;provided, however, that such Indebtedness is extinguished within five business days after receipt of notice of its Incurrence by the Issuer or Guarantor, as applicable.

     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 (15) above, or is entitled to be Incurred pursuant to the first paragraph of this covenant, Compton or the applicable Restricted Subsidiary will be permitted to classify such item of Indebtedness in whole or in part in any manner that complies with the applicable part of this covenant, including by allocation to more than one other type of Indebtedness. In addition, any Indebtedness originally classified as Incurred pursuant to clauses (1) through (15) above may later be reclassified by the Issuer such that it will be deemed as having been Incurred pursuant to another of such clauses to the extent that such reclassified Indebtedness could be Incurred pursuant to such new clause at the time of such reclassification. Notwithstanding the foregoing, Indebtedness under Credit Facilities outstanding on the Issue Date 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.

     Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that may be Incurred pursuant to this covenant will not be deemed to be exceeded with respect to any outstanding Indebtedness due solely to the result of fluctuations in currency exchange rates.

     Neither Compton nor the Issuer will Incur any additional Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of Compton or the Issuer, respectively, unless such additional Indebtedness is also contractually subordinated in right of payment to the Parent Guarantee or the Notes, as applicable, on substantially identical terms. Neither Compton nor the Issuer will permit any Subsidiary Guarantor to Incur any Indebtedness that is subordinated in right of payment to any other Indebtedness of such Subsidiary Guarantor unless it is subordinated in right of payment to such Subsidiary Guarantor’s Subsidiary Guarantee on substantially identical terms. For purposes of the foregoing, no Indebtedness of the Issuer or any Guarantor will be deemed to be contractually subordinated in right of payment to any other Indebtedness of the Issuer or such Guarantor solely by reason of any Liens or guarantees arising or created in respect thereof or by virtue of the fact that the holders of any secured Indebtedness have entered into intercreditor agreements giving one or more of such holders priority over the other holders in the collateral held by them.

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     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, and Obligations in respect thereof, 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 (or, in the case of Indebtedness subordinated to the Notes or the related Guarantees, prior thereto, with the same relative priority as the Notes will have with respect to such subordinated Indebtedness) 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 of Compton to:

(1)	pay dividends or make any other distributions on its Capital Stock (or with respect to any other interest or participation in, or measured by, its profits) to Compton or any of its Restricted Subsidiaries 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.

     In addition, Compton will not, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on its or any Subsidiary Guarantor’s ability to:

(1)	pay dividends (as applicable) or make distributions to the Issuer or pay any Indebtedness and Obligations in respect thereof owed to the Issuer;
(2)	make loans or advances to the Issuer; or
(3)	transfer any of its properties or assets to the Issuer.

     However, the restrictions in the preceding two paragraphs will not apply to encumbrances or restrictions existing under or by reason of:

(1)	agreements governing Existing Indebtedness or Credit Facilities or any other agreements as in effect or which come into effect on the Issue Date and any amendments, modifications, restatements, renewals, extensions, increases, supplements, refundings, replacements or refinancings of those agreements,provided thatthe amendments, modifications, restatements, renewals, extensions, increases, supplements, refundings, replacements or refinancings are not materially more restrictive, taken as a whole, than those contained in the relevant agreement as in effect on the Issue Date, as determined by Compton’s Board of Directors in their reasonable and good faith judgment;
(2)	the indenture, the Notes and the 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 the encumbrance or restriction contained in the instrument governing 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;

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(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 two paragraphs;
(7)	any agreement for the sale or other disposition of the Capital Stock or all or substantially all of the assets of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;
(8)	Permitted Refinancing Indebtedness,provided thatthe restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced, as determined by Compton’s Board of Directors in their reasonable and good faith judgment;
(9)	Liens securing Indebtedness and Obligations in respect thereof 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;
(10)	customary restrictions on the disposition or distribution of assets or property, in each case contained in joint venture agreements and other similar agreements entered into in the ordinary course of business; and
(11)	restrictions on cash or other deposits or net worth imposed by customers or required by insurance, surety or bonding companies, in each case, under contracts entered into in the ordinary course of business.

     Amalgamation, Merger, Consolidation or Sale of Assets

     Neither Compton nor the Issuer may, directly or indirectly: (1) amalgamate, consolidate or merge with or into another Person (whether or not Compton or the Issuer is the surviving Person); 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 or the Issuer is the surviving Person or (b) the Person formed by or surviving any such amalgamation, consolidation or merger (if other than Compton or the Issuer) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a Person (or, in the case of the Issuer, 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 amalgamation, consolidation or merger (if other than Compton or the Issuer) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of (a) Compton under its Parent Guarantee or the Issuer under the Notes, as the case may be, and (b) of Compton or the Issuer, as applicable, under the Indenture and the Registration Rights Agreement, in each case, pursuant to agreements reasonably satisfactory to the trustee;
(3)	immediately after such transaction no Default or Event of Default exists;
(4)	Compton or the Person formed by or surviving any such amalgamation, consolidation or merger (if other than Compton or the Issuer), 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

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(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”;

(5)	each Subsidiary Guarantor, unless such Subsidiary Guarantor is the Person with which Compton or the Issuer, as the case may be, has entered into a transaction under this covenant, will have by amendment to its Subsidiary Guarantee confirmed that its Subsidiary Guarantee will apply to the obligations of the Issuer or the surviving Person in accordance with the Notes and the indenture; and
(6)	the transactions will not result in Compton or the Issuer 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 or the Issuer, as applicable, would not have been required to make had such transactions or series of transactions not occurred.

     In addition, neither Compton nor the Issuer may, directly or indirectly, lease all or substantially all of its properties or assets, in one or more related transactions, to any other Person. Clause (4) of this “Amalgamation, 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 or the Issuer and any of the Subsidiary 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, at the time of the transaction, in a comparable transaction by Compton or such Restricted Subsidiary with a Person that is not an Affiliate of Compton or any of its Restricted Subsidiaries; and
(2)	Compton or the Issuer 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 of Compton 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 of Compton; and

(b)

with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of US$20.0 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;

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(3)	transactions with a Person (other than an Unrestricted Subsidiary) 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 any directors, or the execution of customary expense reimbursement, indemnification or similar arrangements with any directors and officers, of the Issuer or Compton or its Restricted Subsidiaries in the ordinary course of business;
(5)	sales of Equity Interests (other than Disqualified Stock) of Compton;
(6)	Restricted Payments that are permitted by the provisions of the indenture described above under the caption “— Restricted Payments” and Permitted Investments (other than pursuant to clauses (3) and (8) of the definition of Permitted Investments);
(7)	any transaction pursuant to any agreement in existence on the Issue Date and disclosed in this short form prospectus, or any amendment, replacement or refinancing thereof that, taken in its entirety, is no less favourable to Compton and its Restricted Subsidiaries than such agreement in effect on the Issue Date; and
(8)	any sale of securities (including Disqualified Stock but excluding other Equity Interests) made to an Affiliate on the same terms as are being made to the non-Affiliate investors in any public or private sale of such securities; provided that any such sale complies with the requirements of clause (1) of the first paragraph of this covenant.

     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 such supplemental indenture has been duly authorized, executed and delivered and constitutes a legal, valid, binding and enforceable obligation of that Restricted Subsidiary, Compton, the Issuer and the other Subsidiary Guarantors party thereto, all within ten Business Days of the date on which it was acquired or created;provided, however, that if such new Restricted Subsidiary is acquired pursuant to a take-over bid in which less than 90% of the Capital Stock (on a fully diluted basis) of such Restricted Subsidiary is acquired, then the aforementioned supplemental indenture providing for a Subsidiary Guarantee and corresponding Opinion of Counsel shall be provided within ten business days of the acquisition of 90% or more of the subject Capital Stock (on a fully diluted basis) and, in any event, no later than within 120 days of the date on which the Capital Stock of such newly acquired Restricted Subsidiary was first taken up and paid for under the take-over bid.

     Designation of Unrestricted and Restricted Subsidiaries

     The Board of Directors of Compton may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if no Default or Event of Default would be in existence following such designation;providedthat:

(1)	the aggregate Fair Market Value of all outstanding Investments owned by Compton and its Restricted Subsidiaries in the Subsidiary so designated (including any guarantee by Compton or any Restricted Subsidiary of any Indebtedness of such Subsidiary) will be deemed to be an Investment made as of the time of the designation and that such Investment would be permitted under the covenant described above under the caption “— Restricted Payments”;
(2)	any guarantee by Compton or any Restricted Subsidiary thereof of any Indebtedness of the Subsidiary being so designated will be deemed to be an Incurrence of Indebtedness by Compton or such Restricted Subsidiary (or both, if applicable) at the time of such designation, and such Incurrence of Indebtedness would be permitted under the covenant described above under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;” and
(3)	such Subsidiary does not hold any Liens on any property of Compton or any Restricted Subsidiary thereof;

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provided, further, that such designation will only be permitted if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

     The Board of Directors of Compton may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary;providedthat:

(1)	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 such Indebtedness is permitted under the covenant described under the caption “— 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)	all outstanding Investments owned by such Unrestricted Subsidiary will be deemed to be made as of the time of such designation and such designation will only be permitted if such Investments would be permitted under the covenant described above under the caption “—Restricted Payments;”
(3)	all Liens upon property or assets of such Unrestricted Subsidiary existing at the time of such designation would be permitted under the caption “—Liens;”
(4)	no Default or Event of Default would be in existence following such designation; and
(5)	such Unrestricted Subsidiary becomes a Subsidiary 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.

     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.

     Compton will not permit Compton Holdings or any other Restricted Subsidiary of Compton, for so long as any such Person owns any of the Acquired 9.90% Notes, to own any assets (other than such Acquired 9.90% Notes), incur any liabilities (other than intercompany Indebtedness in respect of amounts borrowed by such Person to purchase such Acquired 9.90% Notes or guarantees of Indebtedness (or Obligations in respect thereof) permitted to be Incurred under the indenture) or have any operations.

     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 Holders 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 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 the Issuer or on behalf of the Issuer with respect to the Notes, or by any Guarantor pursuant to the Guarantees, 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 the Issuer or a Guarantor 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, the Issuer or such Guarantor will:

(1) make such withholding or deduction;

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(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 the Issuer or such Guarantor 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
(b)	any taxes imposed with respect to any reimbursement under the preceding clause (a) or this clause (b), 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 and on the date Additional Amounts are payable, deliver to the trustee an amount of money equal to the Additional Amounts.

     Notwithstanding the foregoing, neither the Issuer nor a Guarantor will pay Additional Amounts to a Holder in respect of a beneficial owner of a note:

(1)	with which the Issuer does not deal at arm’s length (within the meaning of the Income Tax Act (Canada)) at the time of making such payment; or
(2)	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, the purchase price pursuant to a Change of Control Offer or Asset Sale Offer, 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. The Issuer’s and the Guarantors’ 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 “— Certain Income Tax Considerations — Canadian Federal Income Tax Considerations”.

     Reports

     Whether or not required by the SEC, so long as any Notes are outstanding, Compton will furnish to the trustee and, upon request, will furnish to beneficial owners of and prospective investors in the Notes a copy of all of the information and reports referred to in clauses (1) and (2) below within the time periods specified in the SEC’s rules and regulations:

(1) (a)  all annual financial information that Compton would have been required to file with the SEC on Forms 20-F or 40-F, as applicable (or any successor forms), containing the information required therein (or required in such successor form), if Compton was required to file such

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	Forms and was a reporting issuer under the securities laws of the Province of Alberta or Ontario; and
(b)	for the first three quarters of each year, all quarterly financial information that Compton would have been required to file or furnish with the SEC on Form 6-K (or any successor form), if Compton was required to file or furnish, as applicable, such Form and was a reporting issuer under the securities laws of the Province of Alberta or Ontario, and

	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 independent accountants; and
(2)	all current reports that would otherwise be required to be filed or furnished by Compton with the SEC on Form 6-K if Compton was required to file or furnish, as applicable, such Form and was a reporting issuer under the securities laws of the Province of Alberta or Ontario.

     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 and Results of Operations, of the financial condition and results of operations of Compton and its Restricted Subsidiaries excluding the Unrestricted Subsidiaries;provided, however, that if the Unrestricted Subsidiaries, on a combined basis, are “minor” (as defined in Rule 3-10(h)(6) of Regulation S-X under the Securities Act) then disclosure to that effect will be sufficient for purposes of this paragraph.

     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 TSX. In addition, following the consummation of the Exchange Offer contemplated by the Registration Rights Agreement, whether or not required by the SEC, Compton will file a copy of all of the information and reports referred to in clauses (1) and (2) above with the SEC for public availability within the time periods specified in the SEC’s rules and regulations (unless the SEC will not accept such a filing). If, notwithstanding the foregoing, the SEC will not accept Compton’s filings for any reason, Compton will post the reports referred to in the preceding paragraph on its website within the time periods that would apply if Compton were required to file those reports with the SEC.

     Notwithstanding the foregoing:

(1)

if at any time Compton (or any successor) is not both a Guarantor and the parent company of the Issuer; or

(2)

if at any time subsequent to consummation of the Exchange Offer, the Issuer, if it was required to file or furnish, as applicable, the reports described in the first paragraph of this covenant, would not (by virtue of Compton’s reports being provided pursuant to the first paragraph of this covenant) be exempt from the obligation to file its own reports with the SEC pursuant to either (x) the provisions of Rule 12h-5 of the Exchange Act (or any successor provision thereto) or (y) if applicable, an equivalent exemption or relief from the corresponding reporting requirements under Canadian securities laws;

the reports, information and other documents of Compton required to be filed and provided as described above shall be those of, in the case of clause (1), the Issuer (combined, as applicable, with the information of existing Guarantors whose results would not otherwise be consolidated with those of the Issuer and its Subsidiaries) or, in the case of clause (2), both Compton and the Issuer.

     In addition, Compton, the Issuer and the Subsidiary Guarantors have agreed that, for so long as any Notes remain outstanding, they will furnish to the Holders and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

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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 (whether at maturity, upon acceleration, redemption or otherwise) 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 — Amalgamation, 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 consecutive days after written notice has been given to the Issuer by the trustee or to the Issuer 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 outstanding principal amount of any such Indebtedness, together with the outstanding 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$20.0 million or more,provided thatif any such default is cured or waived or any such acceleration is rescinded, or such Indebtedness is repaid, within a period of 30 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$20.0 million, which judgments are not paid, discharged or stayed for a period of 60 days;
(7)	except as permitted by the indenture, (a) any 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 (each such event being a “Deficiency”) or (b) Compton or any Significant Subsidiary, or any Person acting on behalf of Compton or any Significant Subsidiary, shall deny or disaffirm its obligations under its Guarantee;providedthat, for purposes of clause (a), to the extent the Guarantee is of a Subsidiary Guarantor that, together with all other Subsidiary Guarantors whose Guarantees have been held unenforceable or invalid or have ceased for any reason to be in full force and effect, would not in aggregate constitute a Significant Subsidiary, such Deficiency shall not be an Event of Default unless the Deficiency continues for a period of 30 days; and

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(8) certain events of bankruptcy or insolvency described in the indenture with respect to Compton, the Issuer or any of Compton’s Significant Subsidiaries (or any Restricted Subsidiaries that together would constitute a Significant Subsidiary).

     In the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to the Issuer, Compton, any Subsidiary of Compton that is a Significant Subsidiary or any group of Subsidiaries that, taken together, would constitute a Significant Subsidiary of Compton, 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 by notice in writing to the Issuer specifying the Event of Default.

     Holders 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 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 or that may involve the trustee in personal liability.

     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 other than non-payment resulting from a declaration of acceleration. 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. However, the trustee may refuse to follow any direction that conflicts with law or the indenture, that may involve the trustee in personal liability, or that the trustee determines in good faith may be unduly prejudicial to the rights of Holders not joining in the giving of such direction and may take any other action it deems proper that is not inconsistent with any such direction received from Holders. A Holder may not pursue any remedy with respect to the indenture or the Notes unless:

(1)	the Holder gives the trustee written notice of a continuing Event of Default;
(2)	the Holders of at least 25% in aggregate principal amount of outstanding Notes make a written request to the trustee to pursue the remedy;
(3)	such Holder or Holders offer the trustee indemnity satisfactory to the trustee against any costs, liability or expense;
(4)	the trustee does not comply with the request within 60 days after receipt of the request provided that the indemnity, if requested, has been provided by the end of that 60-day period; and
(5)	during such 60-day period, the Holders of a majority in aggregate principal amount of the outstanding Notes do not give the trustee a direction that is inconsistent with the request.

However, such limitations do not apply to the right of any Holder of a Note to receive payment of the principal of, premium or Additional Interest, if any, or interest on, such Note or to bring suit for the enforcement of any such payment, on or after the due date expressed in the Notes, which right will not be impaired or affected without the consent of the Holder.

     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 the Issuer or any Guarantor with the intention of avoiding payment of the premium that the Issuer would have had to pay if the Issuer 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 December 1, 2009, by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Issuer or any Guarantor with the intention of avoiding the prohibition on redemption of the Notes prior to December 1, 2009, then the premium specified in the indenture regarding the redemption of the Notes will also become immediately due and payable to the extent permitted by law upon the acceleration of the Notes.

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     The Issuer 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, the Issuer 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, stockholder, member, manager or partner of Compton, the Issuer or any Subsidiary Guarantor, as such, will have any liability for any obligations of Compton, the Issuer or any Subsidiary Guarantor under the Notes, the indenture, the Guarantees, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder 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

     The Issuer 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 Guarantees (“Legal Defeasance”) except for:

(1)	the rights of Holders 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)	the Issuer’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;
(3)	the rights, powers, trusts, duties and immunities of the trustee, and the Issuer’s and the Guarantor’s obligations in connection therewith; and
(4)	the Legal Defeasance provisions of the indenture.

     In addition, the Issuer may, at its option and at any time, elect to have the obligations of the Issuer 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)

the Issuer must irrevocably deposit with the trustee, in trust, 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, 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 the Issuer must specify whether the Notes are being defeased to maturity or to a particular redemption date;

(2)

in the case of Legal Defeasance, the Issuer must deliver to the trustee an Opinion of Counsel reasonably acceptable to the trustee confirming that (a) the Issuer 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 U.S. 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 U.S. 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;

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(3)	in the case of Covenant Defeasance, the Issuer must deliver to the trustee an Opinion of Counsel reasonably acceptable to the trustee confirming that the Holders 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;
(4)	in the case of Legal Defeasance or Covenant Defeasance, the Issuer must deliver to the trustee an Opinion of Counsel reasonably acceptable to the trustee and qualified to practice in Canada or a ruling from Canada Revenue Agency, to the effect that Holders 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 Legal Defeasance or Covenant Defeasance, as applicable, 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 if such Legal Defeasance or Covenant Defeasance, as applicable, had not occurred;
(5)	no Default or Event of Default has occurred and is continuing either: (a) 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) or (b) insofar as Events of Default from bankruptcy or insolvency events are concerned, at any time in the period ending on the 123rd day after the date of deposit;
(6)	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 the Issuer or any of its Restricted Subsidiaries is a party or by which the Issuer or any of its Restricted Subsidiaries is bound;
(7)	the Issuer must deliver to the trustee an Opinion of Counsel to the effect that (1) assuming no intervening bankruptcy of the Issuer or any Guarantor between the date of deposit and the 123rd day following the deposit and assuming that no Holder is an “insider” of the Issuer under applicable bankruptcy law, after the 123rd day following the deposit, the trust funds will not be subject to the effect of any applicable bankruptcy, insolvency, reorganization or similar laws affecting creditors’ rights generally, including Section 547 of the United States Bankruptcy Code and Section 15 of the New York Debtor and Creditor Law and (2) the creation of the defeasance trust does not violate the U.S. Investment Company Act of 1940;
(8)	the Issuer must deliver to the trustee an Officers’ Certificate stating that the deposit was not made by the Issuer with the intent of preferring the Holders over the other creditors of the Issuer with the intent of defeating, hindering, delaying or defrauding creditors of the Issuer or others;
(9)	if the Notes are to be redeemed prior to their Stated Maturity, the Issuer must deliver to the trustee irrevocable instructions to redeem all of the Notes on the specified redemption date; and
(10)	the Issuer 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 two 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):

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(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 U.S. dollars;
(6)	make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of Holders 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 Guarantee or the indenture, except in accordance with the terms of the indenture;
(9)	amend or modify any of the provisions of the indenture or the related definitions affecting the ranking of the Notes or any Guarantee in any manner adverse to the Holders or any Guarantee;
(10)	impair the right to institute suit for the enforcement of any payment on or with respect to the Notes or the Guarantees; or
(11)	make any change in the preceding amendment and waiver provisions.

     Notwithstanding the preceding, without the consent of any Holder, the Issuer, the Guarantors and the trustee may amend or supplement the indenture, the Notes or the Guarantees:

(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 the Issuer’s and each Guarantor’s obligations to Holders 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 or that does not adversely affect the legal rights under the indenture of any such Holder;
(5)	to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;
(6)	to evidence and provide for the acceptance of appointment by a successor trustee;
(7)	to provide for the issuance of additional Notes in accordance with the indenture; or
(8)	to comply with the provisions described under “—Certain Covenants – Additional Subsidiary Guarantees.”

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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 the Issuer, 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 the Issuer 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 such amounts as will be sufficient (without consideration of any reinvestment of interest) 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 the Issuer or any Guarantor is a party or by which the Issuer or any Guarantor is bound;
(3)	the Issuer or any Guarantor has paid or caused to be paid all sums payable by it under the indenture; and
(4)	the Issuer 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, the Issuer 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 the Issuer 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 SEC for permission to continue or resign.

     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, unless such Holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense.

Additional Information

     Anyone who receives this short form 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.

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Book-Entry, Delivery and Form

     Notes will be issued in registered, global form in minimum denominations of US$1,000 and integral multiples of US$1,000 in excess of US$1,000. The Exchange Notes will be issued and initially will be represented by one or more Notes in registered, global form without interest coupons (the “Global Notes”). The Global Notes will be deposited upon issuance with the trustee as custodian for DTC in New York, New York, and registered in the name of DTC or its nominee in each case for credit to an account of a direct or indirect participant in DTC as described below.

     Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for Notes in certificated form except in the limited circumstances described below. See “- Exchange of Global Notes for Certificated Notes”. Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of Notes in certificated form.

     The following description of the operations and procedures of DTC are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

     The Issuer understands, based on information made publicly available by DTC, that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the Initial Purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

     The Issuer also understands, based on information made publicly available by DTC, that, pursuant to procedures established by DTC:

(1)	upon deposit of the Global Notes, DTC will credit the accounts of Participants designated by the Initial Purchasers with portions of the principal amount of the Global Notes; and
(2)	ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Notes).

     Investors in the Global Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants in such system. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

     Except as described below, owners of a beneficial interest 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” thereof under the indenture for any purpose.

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     Payments in respect of the principal of, and interest and premium and Additional Interest, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the Holder under the indenture. Under the terms of the indenture, the Issuer and the trustee will treat the Persons in whose names the Notes, including the Global Notes, are registered as the owners of the Notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Issuer, the trustee nor any agent of the Issuer or the trustee has or will have any responsibility or liability for:

(1)	any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Notes; or
(2)	any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

     The Issuer understands, based on information made publicly available by DTC, that DTC’s 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 unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of Notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or the Issuer. Neither the Issuer nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the Notes, and the Issuer and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

     Transfers between Participants in DTC will be effected in accordance with DTC’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.

     The Issuer understands, based on information made publicly available by DTC, that DTC will take any action permitted to be taken by a Holder only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the Notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the Notes, DTC reserves the right to exchange the Global Notes for legended Notes in certificated form, and to distribute such Notes to its Participants.

     Although DTC has agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, it is under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. Neither the Issuer nor the trustee nor any of their respective agents will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Notes for Certificated Notes

     A Global Note is exchangeable for definitive Notes in registered certificated form (“Certificated Notes”) if:

(1)	DTC (a) notifies the Issuer that it is unwilling or unable to continue as depository for the Global Notes and the Issuer fails to appoint a successor depository or (b) has ceased to be a clearing agency registered under the Exchange Act;
(2)	the Issuer , at its option, notifies the trustee in writing that it elects to cause the issuance of the Certificated Notes; or
(3)	there has occurred and is continuing a Default or Event of Default with respect to the Notes.

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     In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in “Notice to Investors”, unless that legend is not required by applicable law.

Same Day Settlement and Payment

     The Issuer will make payments in respect of the Notes represented by the Global Notes (including principal, premium, if any, interest and Additional Interest, if any) by wire transfer of immediately available funds to the accounts specified by the Global Note Holder. The Issuer will make all payments of principal, interest and premium and Additional Interest, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the Holders of the Certificated Notes or, if no such account is specified, by mailing a check to each such Holder’s registered address. The Notes represented by the Global Notes are expected to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such Notes will, therefore, be required by DTC to be settled in immediately available funds. The Issuer expects 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 DTC 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 DTC. The Issuer understands, based on information made publicly available by DTC, 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 DTC will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC’s settlement date.

Ratings

     The Notes have received a preliminary credit rating of “B2” from Moody’s and “B “from S&P.

     Moody’s credit ratings are on a long-term debt rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of B is the sixth highest of nine categories and denotes obligations judged to be speculative and subject to high credit risk. The addition of a 1, 2 or 3 modifier after a rating indicates the relative standing within a particular rating category. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of its generic rating category.

     S&P’s credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of B by S&P is the sixth highest of 11 categories. According to the S&P rating system, debt securities rated B have significant speculative characteristics but are less vulnerable in the near term than other lower rated obligations. However, an obligor rated B currently has the capacity to meet its financial commitments on its obligation but adverse business, financial or economic conditions will likely impair the obligor’s capacity or willingness to meet its financial commitment on the obligation. The addition of a plus (+) or minus ( — ) designation after a rating indicates the relative standing within a particular rating category.

     Credit ratings are not recommendations to buy, sell or hold securities and may be subject to revision or withdrawal at any time by the rating organization. Ratings are intended to provide investors with an independent measure of the credit quality of an issue or securities. Each rating agency has several categories of long-term debt ratings that may be assigned to a particular issue. Prospective purchasers of the Notes should consult the rating organization with respect to the interpretation and implication of the foregoing ratings and outlooks.

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Certain 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 9.90% Notes” means the 9.90% Senior Notes due 2009 of Compton acquired by Compton Holdings pursuant to the tender offer for such notes by Compton Holdings or otherwise acquired by Compton or any of its Subsidiaries.

“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 “— Certain Covenants — 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 SEC guidelines (before any provincial, state or federal income taxes), as confirmed by a nationally recognized firm of independent petroleum engineers (which shall include Netherland, Sewell & Associates, Inc.) in a reserve report prepared as of the end of Compton’s most recently completed fiscal year, asincreased 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 SEC guidelines (utilizing the prices utilized in such year-end reserve report), anddecreased 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 SEC guidelines (utilizing the prices in such year-end reserve report),providedthat, 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 Netherland, Sewell & Associates, Inc.) delivered to the trustee (which report shall be reasonably satisfactory in form and substance to the trustee);

(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;

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(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 and its Restricted Subsidiaries 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;

minusthe sum of the following to the extent that they have not already been taken into account in the calculation pursuant to clauses (1) to (4) above:

(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)	the discounted future net revenues, calculated in accordance with SEC 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 SEC 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 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 SEC guidelines utilizing the prices utilized in Compton’s year-end reserve report, attributable to reserves that are subject to participation interests, royalty interests, overriding interests, net profits interests or other interests of third parties pursuant 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.

     To the extent not already included in the foregoing, “Adjusted Consolidated Net Tangible Assets” will be calculated giving pro forma effect to properties or assets of Compton and its Restricted Subsidiaries the acquisition of which is to be funded by Indebtedness to be Incurred under clause (1) of the second paragraph of the covenant described above under “— Certain Covenants –- Incurrence of Indebtedness and Issuance of Preferred Stock.” 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.

“Additional Interest” means all liquidated damages owing at the applicable time pursuant to the Registration Rights Agreement.

“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:

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(1)

the sale, lease, conveyance or other disposition of any assets or rights;providedthat 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 — Amalgamation, 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;providedthat the issuance or sale of a majority of the Equity Interests in the Issuer will be governed by the provisions of the indenture described above under the caption “— Repurchase at the Option of Holders — Change of Control” and the provisions described above under the caption “— Certain Covenants — Amalgamation, Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant.

Notwithstanding the preceding, the following items will be deemed not to be Asset Sales:

(1)	any single transaction or series of related transactions that involves assets having a Fair Market Value of less than US$3.0 million;
(2)	a transfer of assets between or among Compton and/or its Restricted Subsidiaries;
(3)	an issuance of Equity Interests by a Subsidiary of Compton to Compton or to a Restricted Subsidiary of Compton;
(4)	any sale or disposition 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)	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,providedthat 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 Compton or any Subsidiary of Compton of any oil and gas property owned or held by Compton or such Subsidiary for any oil and gas property owned or held by another Person; provided that the property received by Compton or such Subsidiary in such trade or exchange has a Fair Market Value at least equivalent to the property traded or exchanged; and
(11)	the sale or transfer of hydrocarbons or other mineral products in the ordinary course of business.

“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.

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“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 with respect to any Person:

(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 or A-1 by S&P or at least R-1 by Dominion Bond Rating Service Limited 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:

(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);

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(2)	the adoption or approval by the Board of Directors of Compton or the Issuer or their respective stockholders of a plan relating to the liquidation or dissolution of Compton or the Issuer, as applicable;
(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;
(4)	the first day on which a majority of the members of the Board of Directors of Compton are not Continuing Directors;
(5)	Compton or the Issuer amalgamates or consolidates with, or merges with or into, any Person (other than Compton or any Restricted Subsidiary of Compton), or any Person (other than Compton or any Restricted Subsidiary of Compton) amalgamates or consolidates with, or merges with or into Compton or the Issuer, in any such event pursuant to a transaction in which any of the outstanding Voting Stock of Compton or the Issuer, as the case may be, or such other Person is converted into or exchanged for cash, securities or other property, other than any such transaction where (A) the Voting Stock of Compton or the Issuer, as applicable, outstanding immediately prior to such transaction is converted into or exchanged for Voting Stock (other than Disqualified Stock) of the surviving or transferee Person constituting a majority of the outstanding shares of such Voting Stock of such surviving or transferee Person (immediately after giving effect to such issuance) and (B) immediately after such transaction, no “person” or “group” (as such terms are used in Section 13(d) and 14(d) of the Exchange Act) becomes, directly or indirectly, the Beneficial Owner of 50% or more of the voting power of the Voting Stock of the surviving or transferee Person; or
(6)	the Issuer ceases to be a Subsidiary of Compton.

“Closing Date” means November 22, 2005, the date on which the Initial Notes were originally issued under the Indenture.

“Compton Holdings” means Compton Petroleum Holdings Corporation.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such periodplus:

(1)	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
(2)	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
(3)	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

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(4)	non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business; andminus
(5)	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. Notwithstanding the preceding, the provision for taxes based on the income or profits of, the consolidated interest expense of and the depreciation, depletion and amortization and other non-cash expenses of, a Restricted Subsidiary of Compton will be added to Consolidated Net Income to compute Consolidated Cash Flow of Compton (A) in the same proportion that the Net Income of such Restricted Subsidiary was added to compute such Consolidated Net Income and (B) only to the extent that a corresponding amount would be permitted at the date of determination to be dividended or distributed to Compton by such Restricted Subsidiary without prior governmental approval (that has not been obtained), and without direct or indirect restriction pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Subsidiary or its stockholders, members, managers or partners, as applicable.

“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;providedthat:

(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, members, managers or partners, as applicable;
(3)	the Net Income of any Person acquired during the specified period 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 (1) all current assets of such Person and its Restricted Subsidiaries and (2) 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 Restricted Subsidiaries as of such date as set forth on the most recently available quarterly or annual consolidated

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balance sheet of such Person and its Restricted Subsidiaries (which will be as of a date not more than 90 days prior to the date of computation, and which will not take into account Unrestricted Subsidiaries);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 Issue Date; 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 Fourth Amended and Restated Credit Agreement dated as of the date of the indenture, among Compton, as borrower, certain Canadian chartered banks, as lenders and Bank of Montreal, as administrative 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, extended, replaced or refinanced from time to time, including any agreement extending the maturity of, refinancing, replacing or otherwise restructuring any of the same or adding Subsidiaries of Compton as additional borrowers or guarantors thereunder, and including all or any portion of the Indebtedness and other Obligations under any of the foregoing or any successor or replacement thereof, 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 and/or letters of guarantee, in each case, as amended, restated, extended, 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 such Person 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”. The term “Disqualified Stock” will also include any options, warrants or other rights that are convertible into Disqualified Stock or that are redeemable at the option of the holder, or required to be redeemed, prior to the date that is one year after the date on which the Notes mature.

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“Dollar-Denominated Production Payments” means production obligations recorded as liabilities in accordance with GAAP payable with deliveries of production, the quantities of which are based on prices agreed to by the applicable parties, 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 the Issuer or Compton (other than Disqualified Stock) generating gross proceeds to the Issuer or Compton of at least US$10.0 million other than:

(1)	offerings related to equity securities issuable under any employee benefit plan of Compton or any of its Restricted Subsidiaries; and
(2)	issuances to Compton or any Subsidiary of Compton.

“Existing Indebtedness” means all Indebtedness of Compton and its Subsidiaries (other than Indebtedness under the Credit Agreement or under the Notes or the Guarantees) in existence on the Issue Date after giving effect to the application of the proceeds of (1) the Notes and (2) any borrowings made under the Credit Agreement on the Issue Date, until such amounts are repaid. For greater clarity, “Existing Indebtedness” does not include Indebtedness represented by any of the Acquired 9.90% Notes or any other intercompany Indebtedness, including intercompany Indebtedness Incurred by Compton Holdings or any other Restricted Subsidiary to fund its purchase of any Acquired 9.90% Notes.

“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, Fair Market Value shall be determined, except as otherwise specified, (1) if the Fair Market Value is equal to or less than US$15.0 million, by the principal financial officer of Compton acting reasonably and in good faith (and, if the Fair Market Value exceeds US$1.0 million, such determination shall be evidenced by an Officers’ Certificate) and (2) if the Fair Market Value exceeds US$15.0 million, by the Board of Directors of Compton acting reasonably and in good faith and shall be evidenced by a resolution of the Board of Directors of Compton attached to an Officers’ Certificate.

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(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, letter of guarantee or bankers’ acceptance financings, and net of the effect of all payments made or received pursuant to Hedging Obligations;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 (other than such Person or its Restricted Subsidiaries) that is guaranteed by such Person 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 or preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests (other than Disqualified Stock) of the Person or to the Person or a Restricted Subsidiary of the Person , times

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(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, 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 givingpro formaeffect to such Incurrence, 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 and dispositions of business entities or property and assets constituting a division or line of business of any Person 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, will be excluded;
(3)	the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, 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; and
(4)	consolidated interest expense attributable to interest on any Indebtedness (whether existing or being Incurred) computed on apro formabasis and bearing a floating interest rate will be computed as if the rate in effect on the Calculation Date (taking into account any interest rate option, swap, cap or similar agreement applicable to such Indebtedness if such agreement has a remaining term in excess of 12 months or, if shorter, at least equal to the remaining term of such Indebtedness) had been the applicable rate for the entire period.

“GAAP” means generally accepted accounting principles, consistently applied, which are in effect in Canada from time to time.

“Government Securities” means securities that are direct obligations of, or obligations guaranteed by, the United States of America, for the timely payment of which its full faith and credit is pledged.

“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, letters of guarantee or reimbursement agreements in respect thereof, of all or any part of any Indebtedness.

“Guarantees” means the Parent Guarantee and the Subsidiary Guarantees.

“Guarantors” means Compton and the Subsidiary Guarantors.

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“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.

“Incur” means, with respect to any Indebtedness, to Incur, create, issue, assume, guarantee or otherwise become directly or indirectly liable for or with respect to, or become responsible for, the payment of, contingently or otherwise, such Indebtedness (and “Incurrence” and “Incurred” will have meanings correlative to the foregoing);providedthat (1) any Indebtedness of a Person existing at the time such Person becomes a Restricted Subsidiary of Compton will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary of Compton and (2) neither the accrual of interest nor the accretion of original issue discount nor the payment of interest in the form of additional Indebtedness with the same terms and the payment of dividends on Disqualified Stock or preferred stock in the form of additional shares of the same class of Disqualified Stock or preferred stock (to the extent provided for when the Indebtedness or Disqualified Stock or preferred stock on which such interest or dividend is paid was originally issued) will be considered an Incurrence of Indebtedness;providedthat in each case the amount thereof is for all other purposes included in the Fixed Charges and Indebtedness of Compton or its Restricted Subsidiary as accrued.

“Indebtedness” means, with respect to any specified Person at any date, any indebtedness of such Person, whether or not contingent and without duplication:

(1)	in respect of borrowed money;
(2)	evidenced by bonds, notes, debentures or similar instruments or letters of guarantee 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 (x) 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),providedthat the amount of such Indebtedness will be the lesser of (A) the Fair Market Value of such asset at such date of determination and (B) the amount of such Indebtedness, and (y) 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 the outstanding balance at such date of all unconditional obligations as described above and, with respect to contingent obligations, the maximum liability upon the occurrence of the contingency giving rise to the obligation, and 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.

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“Initial Purchasers” means Credit Suisse First Boston LLC, Morgan Stanley & Co. Incorporated, Harris Nesbitt Corp., Hibernia Southcoast Capital, Inc., Scotia Capital (USA) Inc., and TD Securities (USA) LLC.

“Initial Subsidiary Guarantors” means all of the Restricted Subsidiaries of Compton existing on the Issue Date (except the Issuer), including Hornet Energy Ltd., Compton Petroleum (partnership) and Compton Petroleum Holdings Corporation.

“Initial Unrestricted Subsidiaries” means Compton Petroleum (U.S.A.) Corporation and Redwood Energy (U.S.A.) Ltd.

“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.

“Investment Grade Ratings” means a rating equal to or higher than BBB- , in the case of S&P (or its equivalent under any successor rating categories of S&P), and a rating equal to or higher than Baa3, in the case of Moody’s (or its equivalent under any successor rating categories of Moody’s).

“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 or other extensions of credit (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 Restricted Subsidiary of Compton sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of Compton such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of Compton, Compton or such Restricted Subsidiary will be deemed to have made an Investment on the date of any such sale or disposition equal to the Fair Market Value of the Investments in such Subsidiary that were not sold or disposed of. The acquisition by Compton or any Restricted 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 Restricted 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.

“Issue Date” means the date of original issuance of the Initial Notes under the indenture.

“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 estimated discounted future net cash flows from the following will be excluded from the calculation of Material Change:

(1)	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 Netherland, Sewell & Associates, Inc.); and
(2)	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 “—Repurchases at the Option of the Holders— Asset Sales”.

“Moody’s” means Moody’s Investors Service, Inc. and its successors.

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“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 or loss, together with any related provision for taxes on such gain or loss, realized in connection with: (a) any sale of assets outside the ordinary course of business of such Person; 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;
(2)	any extraordinary gain or loss, together with any related provision for taxes on such extraordinary gain or loss; and
(3)	any unrealized foreign exchange gain (or loss) on long-term debt.

“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 (1) the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking and brokerage fees, and sales commissions, and any relocation expenses Incurred as a result of the Asset Sale, (2) 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, (3) amounts required to be applied to the repayment of Indebtedness (and Obligations in respect thereof), other than Indebtedness (and Obligations in respect thereof) under a Credit Facility secured by a Lien on the asset or assets that were the subject of such Asset Sale, (4) any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP, (5) in the case of any Asset Sale by a Restricted Subsidiary of Compton, payments to holders of Equity Interests in such Restricted Subsidiary in such capacity (other than such Equity Interests held by Compton or any Restricted Subsidiary thereof) to the extent that such payment is required to permit the distribution of such proceeds in respect of the Equity Interests in such Restricted Subsidiary held by Compton or any Restricted Subsidiary thereof and (6) appropriate amounts to be provided by Compton or its Restricted Subsidiaries as a reserve against liabilities associated with such Asset Sale, including, without limitation, pension and other post-employment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale, all as determined in accordance with GAAP;providedthat (a) excess amounts set aside for payment of taxes pursuant to clause (2) above remaining after such taxes have been paid in full or the statute of limitations therefor has expired and (b) amounts initially held in reserve pursuant to clause (6) no longer so held, will, in the case of each of subclause (a) and (b), at that time become Net Proceeds.

“Obligations” means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

“Officer” means, with respect to any Person, the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, the Treasurer, any Assistant Treasurer, the Controller, the Secretary or any Vice President of such Person.

“Officers’ Certificate” means a certificate signed on behalf of Compton by at least two Officers of Compton, one of whom must be the principal executive officer, the principal financial officer or the principal accounting officer of Compton, that meets the requirements of the indenture.

“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;

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(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;

providedin respect of Compton and the Restricted Subsidiaries that 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 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 the prices of oil and gas and other commodities used or useful in the Oil and Gas Business, including contracts settled by physical delivery of the commodity not settled within 60 days of the date of any such contract;providedthat Production Payments will not be treated as Oil and Gas Hedging Contracts for the purposes of the indenture.

“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.

“Opinion of Counsel” means an opinion from legal counsel who is reasonably acceptable to the trustee (who may be counsel to or an employee of the Issuer or Compton) that meets the requirements of the indenture.

“Parent Guarantee” means Compton’s guarantee of the Notes and the Restricted Subsidiaries’ obligations under their Subsidiary Guarantees.

“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;

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(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, in each case, not for speculative purposes;
(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;
(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) since the Issue Date, not to exceed US$10.0 million; and
(11)	stock, obligations or securities received in satisfaction of judgements.

“Permitted Liens” means, as of any date:

(1)	Liens on assets of Compton and any Restricted Subsidiary securing Indebtedness Incurred under clause (1) of the second paragraph of the covenant described under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” and Obligations in respect of such Indebtedness;
(2)	Liens in favor of the Issuer 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 Indebtedness and Obligations under Oil and Gas Hedging Contracts permitted by clauses (7) and (10), respectively, of the second paragraph of the covenant entitled “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock”;
(5)	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;
(6)	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;

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(7)	Liens on property existing at the time of acquisition of the property by Compton or any Restricted Subsidiary of Compton,providedthat such Liens were in existence prior to the contemplation of such acquisition and such Liens do not extend to any assets other than the property being acquired;
(8)	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;
(9)	Liens to secure Indebtedness and Obligations in respect thereof (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;
(10)	Liens existing on the date of the indenture;
(11)	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;
(12)	Liens in pipelines or pipeline facilities that arise by operation of law;
(13)	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 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;
(14)	Liens reserved in oil and gas mineral leases for bonus or rental payments and for compliance with the terms of such leases;
(15)	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;
(16)	Liens securing Permitted Refinancing Indebtedness in respect of Permitted Debt that was secured by Permitted Liens above and securing similar property; and
(17)	statutory and common law Liens of landlords and carriers, warehousemen, mechanics, suppliers, materialmen, repairmen or other similar Liens, in each case arising in the ordinary course of business and with respect to amounts not yet delinquent or being contested in good faith by appropriate legal proceedings promptly instituted and diligently conducted and for which a reserve or other appropriate provision, if any, as shall be required in conformity with GAAP shall have been made.

“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 or Obligations in respect thereof (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);

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(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 or the Guarantees, such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of the Notes, and is subordinated in right of payment to the Notes or the Guarantees, as applicable, on terms at least as favorable, taken as a whole, to the Holders as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and
(4)	such Indebtedness is Incurred by (a) Compton, (b) the Issuer or (c) 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.

“Rating Agencies” means S&P and Moody’s.

“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 and, for purposes of the indenture, shall include the Issuer.

“S&P” means Standard & Poor’s Ratings Group, a division of the McGraw-Hill Companies, and its successors.

“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 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.

“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).

For purposes of the indenture, for so long as Compton, the Issuer and their respective Subsidiaries collectively own, in aggregate, more than 50% of the total voting power of the Capital Stock of Compton Petroleum (partnership), Compton Petroleum (partnership) shall be a “Subsidiary”.

“Subsidiary Guarantees” means the guarantees of the Notes provided by the Subsidiary Guarantors.

“Subsidiary Guarantors” means each of:

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(1)	the Initial Subsidiary Guarantors; and
(2)	any other Subsidiary that executes a Subsidiary Guarantee in accordance with the provisions of the indenture;

and their respective successors and assigns.

“Unrestricted Subsidiary” means:

(1)

on the Issue Date, the Initial Unrestricted Subsidiaries; and

(2)

subsequent to the Issue Date, any other Subsidiary of Compton that is designated by the Board of Directors of Compton as an Unrestricted Subsidiary pursuant to a resolution by the Board of Directors of Compton and in accordance with the covenant described above under the caption “— Certain Covenants — Designation of Unrestricted and Restricted Subsidiaries,” but only to the extent that such Subsidiary:

(a)	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;
(b)	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;
(c)	has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of Compton or any of its Restricted Subsidiaries; and
(d)	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 Restricted Subsidiary of Compton as an Unrestricted Subsidiary pursuant to clause (2) above will be evidenced to the trustee by filing with the trustee a certified copy of the resolution of the Board of Directors of Compton giving effect to such designation and an Officers’ Certificate certifying that such designation complied with the preceding conditions and the conditions described above under the caption “— Certain Covenants — Designation of Unrestricted and Restricted Subsidiaries.” 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, Investments, or Liens on the property, of such Subsidiary will be deemed to be Incurred or made by a Restricted Subsidiary of Compton as of such date and, if such Indebtedness, Investments or Liens are not permitted to be Incurred or made as of such date under the indenture, the Issuer will be in default under the indenture.

“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

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	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.

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CERTAIN 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 should 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 Initial 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 Stikeman Elliott LLP, our Canadian legal counsel, the following is, as of the date of this short form prospectus, a fair and adequate opinion of the principal Canadian federal income tax consequences to a beneficial owner of the Notes who is a non-resident of Canada. This opinion is based on the current provisions of theIncome Tax Act(Canada) and the regulations under that Act, counsel’s understanding of the current published administrative practices of the Canada Revenue Agency, and all specific proposals to amend theIncome Tax Act(Canada) and the regulations publicly announced by the Minister of Finance prior to the date of this short form prospectus. This opinion does not otherwise take into account or anticipate changes in the law, whether by judicial, governmental or legislative decision 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, we will deal with the beneficial owners of Notes (and with DTC) at arm’s length within the meaning of theIncome Tax Act(Canada), and that we 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.

     The payment by us of interest or principal on the Notes to a beneficial owner who is a non-resident of Canada and with whom we deal at arm’s length within the meaning of theIncome 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 theIncome Tax Act(Canada), related persons (as defined in theIncome 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 theIncome Tax Act(Canada) on the holding, redemption or disposition of the Notes, or the receipt of interest on the Notes by beneficial owners who are neither resident nor deemed to be resident in Canada for the purposes of theIncome 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 theIncome Tax Act(Canada), except that in some circumstances beneficial owners who are non-resident insurers carrying on an insurance business in Canada and elsewhere may be subject to those taxes.

United States Federal Income Tax Considerations

     The following summary describes certain United States federal income tax consequences of the exchange of Initial Notes for Exchange Notes in accordance with the Exchange Offer as well as the ownership and disposition of Exchange Notes by United States persons (as defined below) who hold the Notes as capital assets (“United States Holders”) within the meaning of section 1221 of the Internal Revenue Code of 1986 (as amended, the “Code”). This discussion does not purport to deal with all aspects of U.S. federal income taxation that may be relevant to particular holders 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, traders in securities that elect to use a mark-to-market method of accounting for their securities holdings, traders in securities that elect to use a mark-to-market method of accounting for their securities holdings, financial institutions, insurance companies, tax-exempt organizations, partnerships or other pass-through entities, persons holding Exchange Notes as a part of a straddle, hedge or conversion transaction or a synthetic security or other integrated transaction, United States Holders whose “functional currency” is not the United States dollar, and holders who are not United States Holders. In addition, this summary does not address tax consequences applicable to persons who do not acquire Exchange Notes pursuant to the Exchange Offer.

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Furthermore, the discussion below is based upon the provisions of the Code and regulations, rulings and judicial decisions under the Code as of the date of this short form prospectus, and those authorities may be repealed, revoked or modified (possibly with retroactive effect) so as to result in federal income tax consequences different from those discussed below. There can be no assurance that the Internal Revenue Service (“IRS”) will take a similar view as to any of the tax consequences described in this summary.

     Persons considering the ownership or disposition of Exchange Notes should consult their own tax advisors concerning the United States 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 an Exchange Note that is: (i) a citizen or resident of the United States, (ii) a corporation or other entity treated as a corporation for United States federal income tax purposes, 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.

     If a partnership or other flow-through entity holds an Exchange Note, the United States federal income tax treatment of a partner or other owner generally will depend on the status of the partner or other owner and the activities of the partnership or other flow-through entity. A United States Holder that is a partner of the partnership or an owner or another flow-through entity holding an Exchange Note should consult its own tax advisor.

Exchange of Initial Notes for Exchange Notes

     The exchange of Initial Notes for Exchange Notes should not constitute a recognition event for United States federal income tax purposes. Consequently, no gain or loss should be recognized by a United States Holder upon receipt of the Exchange Notes. For purposes of determining gain or loss upon the subsequent sale or exchange of Exchange Notes, a United States Holder’s adjusted basis in the Exchange Notes should be the same as that United States Holder’s adjusted basis in the Initial Notes exchanged for the Exchange Notes. In addition, a United States Holder’s holding period of Exchange Notes should include the holding period of the Initial Notes exchanged for the Exchange Notes.

Payments of Interest

     Interest on an Exchange 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 Exchange Notes, a United States Holder will be required to include in income any additional amounts received pursuant to the section of this short form prospectus entitled “Description of the Notes — Optional Redemption” and any taxes withheld from interest payments, notwithstanding that the United States Holder does not in fact receive such withheld taxes. It is not expected that the Exchange Notes will be issued with original issue discount (“OID”). If, however, the Exchange Notes are issued with more than ade minimis amount of OID, then such OID would be treated for United States federal income tax purposes as accruing over the Notes’ term as interest income of the United States Holders. A United States Holder’s adjusted tax basis in a note would be increased by the amount of any OID included in its gross income. In compliance with United States Treasury regulations, if we determine that the Exchange Notes have OID, we will provide certain information to the IRS and/or United States Holders that is relevant to determining the amount of OID in each accrual period.

     A United States Holder may be entitled to claim a credit against its United States federal income tax liability, or a deduction in computing its United States 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. Interest income on an Exchange Note generally will constitute foreign source income and, with certain exceptions, generally will be treated separately from other types of income in computing the foreign tax credit allowable to United States Holders under the Code. For taxable years beginning before January 1, 2007, interest income on an Exchange Note generally will be considered “passive income” or “financial services income.” For taxable years beginning after December 31, 2006, interest income on an Exchange Note generally will be considered either “passive category income” or “general category income” for United States foreign tax credit purposes. 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.

     The interest rate on the Exchange Notes will be increased if we fail to either complete the Exchange Offer or cause resales of the Exchange Notes to be registered under the Securities Act before applicable deadlines. You should refer to the section of this short form prospectus entitled “Description of the Notes — Registration Rights; Additional Interest”. We believe that the likelihood of this increase in the rate is remote, and therefore do not intend to treat the possibility of a change in the interest rate as affecting the yield to maturity of any note. If, however, the interest rate were increased because of this non-compliance, a United States Holder would be required to include in gross income any increased amount of interest over the remaining term of the Exchange Notes, possibly in advance of the receipt of cash relating to the increase.

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Market Discount and Bond Premium

     If a United States Holder purchased an Initial Note prior to this exchange offer for an amount that is less than its principal amount, then, subject to a statutory de minimus 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, redemption, 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.

     Market discount generally accrues on a straight-line basis over the remaining term of the exchange note. Upon an irrevocable election, however, market discount will accrue on a constant yield basis. A United States Holder might be required to defer all or a portion of the interest expense on indebtedness incurred or continued to purchase or carry an exchange note. If a United States Holder elects to include market discount in gross income currently as it accrues, 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 prior to this exchange offer for an amount that is in excess of all amounts payable on the Initial Note after the purchase date, other than payments of qualified stated interest, the excess will be treated as bond premium. If a United States Holder exchanges an Initial Note, with respect to which there is a 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. The amount of bond premium allocable to any accrual period is offset against the qualified stated interest allocable to the accrual period. If, following the offset determination described in the immediately preceding sentence, there is an excess allocable bond premium remaining, that excess may, in some circumstances, be deducted. 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 capital 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 United States Holder’s cost for the Exchange Note. Gain or loss realized on the sale, exchange or redemption of an Exchange Note 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 non-corporate United States Holders, including 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, unless the gains are attributable to an office or other fixed place of business outside of the United States and certain other conditions are met, 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 an Exchange 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 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 United States 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 United States 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 should consult your own tax advisor with respect to the tax consequences to you of owning, holding, and disposing of an Exchange 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.

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PLAN OF DISTRIBUTION

     Each broker-dealer that receives Exchange Notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of these Exchange Notes. This short form 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 those Initial Notes were acquired as a result of market-making activities or other trading activities. We will promptly send additional copies of this short form prospectus and any amendment or supplement to this short form prospectus to any broker-dealer that requests those documents in the letter of transmittal. Under the Registration Rights Agreement we have agreed that we will make this short form prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any of these resales starting on the date the registration statement is declared effective and for a period ending on the earlier of (i) 180 days after the date the registration statement is declared effective and (ii) the date on which a participating broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities.

     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 these methods of resale, at market prices prevailing at the time of resale, at prices related to these prevailing market prices or negotiated prices. Any of these resales 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 of these broker-dealers and/or the purchasers of any of these 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 these Exchange Notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit of any of these resales of Exchange Notes and any commissions or concessions received by any of these persons may be deemed to be underwriting compensations 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.

     We have agreed to pay all expenses incident to the Exchange Offer (including the expenses of one counsel for the holders of the Initial Notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the Initial Notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

     The Exchange Notes are not being offered and may not be offered or sold, directly or indirectly, in Canada or to or for the account of any resident of Canada in contravention of the securities law of any province or territory of Canada.

STATUTORY RIGHTS OF WITHDRAWAL AND RESCISSION

     Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces, securities legislation further provides a purchaser with remedies for rescission or, in some jurisdictions, damages if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that the remedies for rescission or damages are exercised by the purchasers within the time limit prescribed the securities legislation of the purchaser’s province. The purchaser should refer to any applicable provisions of the securities legislation of the province in which the purchaser resides for the particulars of these rights or consult with a legal advisor. Rights and remedies also may be available to purchasers under U.S. laws. Purchasers may with to consult with a U.S. legal advisor for particulars of these rights.

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LEGAL MATTERS

     Legal matters in connection with this Exchange Offer will be passed upon for us by Paul, Weiss, Rifkind, Wharton & Garrison LLP, New York, New York (concerning matters of U.S. law) and Stikeman Elliott LLP (concerning matters of Canadian law). The partners of Paul, Weiss, Rifkind, Wharton & Garrison LLP beneficially own less than 1% of our outstanding shares and the partners of Stikeman Elliott 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, 2004 and 2003 was derived from reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers. The reserve information as of December 31, 2002 was evaluated in a report dated January 1, 2003, prepared by Outtrim Szabo Associates Ltd. (now DeGolyer and MacNaughton Canada Limited), independent petroleum engineers. The principals of Netherland, Sewell & Associates, Inc. beneficially own less than 1% of our outstanding shares and the principals of DeGolyer and MacNaughton Canada Limited beneficially own less than 1% of our outstanding shares.

INDEPENDENT ACCOUNTANTS

     Our financial statements, as of December 31, 2004, 2003 and 2002 and for each of the years in the periods ended December 31, 2004, 2003 and 2002, included in this short form prospectus have been audited by Grant Thornton LLP, Chartered Accountants, as stated in their report appearing herein.

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GLOSSARY OF TERMS

     As used in this short form prospectus, the terms set forth below have the meanings indicated.

“bbls” and “mbbls” mean barrels and thousand barrels, respectively.

“boe” and “mboe” mean barrels of oil equivalent and thousand barrels of oil equivalent, respectively. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

“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.

“D&A” means dry and abandoned.

“EUB” means the Alberta Energy and Utilities Board.

“GJ/d” means gigajoules per day.

“light oil” means crude oil with an American Petroleum Institute (API) gravity score that is 26 degrees or greater.

“mcf”, “mmcf”, “bcf” and “tcf” mean thousand cubic feet, million cubic feet, billion cubic feet and trillion cubic feet, respectively.

“mcfe” and “mmcfe” means thousand cubic feet equivalent and million cubic feet equivalent, respectively.

“mlt” means thousand long tons.

“mmbtu” means million British thermal units.

     The terms set forth below, when used in this short form prospectus, have the following meanings, as set forth in National Instrument 51-101 of the Canadian Securities Administrators.

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

“development costs” means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(a)	gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves;
(b)	drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment and the wellhead assembly;

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(c)	acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices, production storage tanks, natural gas cycling and processing plants and central utility and waste disposal systems; and
(d)	provide improved recovery systems.

“development well” means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

“exploration costs” means costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as “prospecting costs”) and after acquiring the property. Exploration costs, which include applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(a)	costs of topographical, geochemical, geological and geophysical studies, rights of access to properties to conduct those studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies (collectively sometimes referred to as “geological and geophysical costs”);
(b)	costs of carrying and retaining unproved properties, such as delay rentals, taxes (other than income and capital taxes) on properties, legal costs for title defense and the maintenance of land and lease records;
(c)	dry hole contributions and bottom hole contributions;
(d)	costs of drilling and equipping exploratory wells; and
(e)	costs of drilling exploratory type stratigraphic test wells.

“exploratory well” means a well that is not a development well, a service well or a stratigraphic test well.

“field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata or laterally by local geologic barriers or both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to denote localized geological features, in contrast to broader terms such as “basin”, “trend”, “province”, “play” or “area of interest”.

“future income tax expense” means future income tax expenses estimated (generally year-by-year):

(a)	making appropriate allocations of estimated unclaimed costs and losses carried forward for tax purposes, between oil and gas activities and other business activities;
(b)	without deducting estimated future costs (for example, crown royalties) that are not deductible in computing taxable income;
(c)	taking into account estimated tax credits and allowances (for example, royalty tax credits); and

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(d) applying to the future pre-tax net cash flows relating to the company’s oil and gas activities and the appropriate year-end statutory tax rates, taking into account future tax rates already legislated.

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

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

“operating costs” means costs incurred to operate and maintain wells and related equipment and facilities, including applicable operating costs of support equipment, facilities and other costs of operating and maintaining those wells and related equipment and facilities.

“production” means recovering, gathering, treating, field or plant processing (for example, processing gas to extract natural gas liquids) and field storage of oil and gas.

“property” includes:

(a)	fee ownership or a lease, concession, agreement, permit, licence or other interest representing the right to extract oil or gas, subject to such terms as may be imposed by the conveyance of that interest;
(b)	royalty interests, production payments payable in oil or gas and other non-operating interests in properties operated by others; and
(c)	an agreement with a foreign government or authority under which a reporting issuer participates in the operation of properties or otherwise serves as producer of the underlying reserves (in contrast to being an independent purchaser, broker, dealer or importer).

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

“reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

“stratigraphic test well” means a drilling effort geologically directed, to obtain information pertaining to a specific geologic condition. Ordinarily, such wells are drilled without the intention of being completed for hydrocarbon production. They include wells for the purpose of core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as:

(a)	“exploratory type” if not drilled into a proved property; or
(b)	“development type”, if drilled into a proved property. Development type stratigraphic wells are also referred to as “evaluation wells”.

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Conversion Factors

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

To Convert From	To	Multiply By
kilometres	miles	0.621
boe	mcfe	6.000
mcf	cubic metres	0.028174
mlt	bbl (on a boe basis)	1.000

136

INDEX TO FINANCIAL STATEMENTS

Consolidated Financial Statements of Compton Petroleum Corporation
Report of Independent Auditors	F-2
Consolidated Balance Sheets — As at September 30, 2005, December 31, 2004 and 2003	F-3
Consolidated Statements of Earnings and Retained Earnings — Nine months ended September 30, 2005 and 2004 and Years ended December 31, 2004, 2003 and 2002	F-4
Consolidated Statements of Cash Flow — Nine months ended September 30, 2005 and 2004 and Years ended December 31, 2004, 2003 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, 2004 and 2003 and the consolidated statements of earnings, retained earnings and cash flow for each of the years in the three year period ended December 31, 2004. 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 standards of the Public Company Accounting Oversight Board (United States). 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 disclosures 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. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2004 and 2003 and the results of its operations and cash flow for each of the years in the three year period ended December 31, 2004 in accordance with accounting principles generally accepted in Canada.

Calgary, Alberta	(Signed) “Grant Thornton LLP”
Canada	Chartered Accountants
March 15, 2005, except for Note 18a)
which is as of November 22, 2005 and Note 18b)
which is as of December 23, 2005

Comments by Auditor for U.S. Readers on Canada-U.S. Reporting Differences

The standards of the Public Company Accounting Oversight Board (United States) 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 change described in Note 2 to the consolidated financial statements. Also, 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 restatement of the Company’s historical financial statements, such as correction of an error in application of accounting principle described in Note 19(f) to the consolidated financial statements. Our report to the shareholders dated March 15, 2005 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles and correction of an error 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 15, 2005

F-2

Compton Petroleum Corporation
Consolidated Balance Sheets

	As at
	September 30,		As at December 31,
	2005		2004		2003
(thousands of dollars)	(unaudited)
Assets
Current
Cash	$	16,900	$	10,068	$	15,548
Accounts receivable and other		120,342		115,113		94,937
Unrealized risk management gain (Note 15a (i))		—		1,985		—
		137,242		127,166		110,485
Property and equipment (Note 5)		1,447,683		1,178,550		942,303
Goodwill (Note 3)		7,914		7,914		—
Deferred financing charges and other		8,281		9,729		11,532
Deferred risk management loss (Note 15a (ii))		6,021		7,252		—
	$	1,607,141	$	1,330,611	$	1,064,320
Liabilities
Current
Bank debt (Note 6)	$	—	$	220,000	$	164,500
Accounts payable		172,386		125,483		85,885
Unrealized risk management loss (Note 15a (i))		30,873		—		—
Income taxes payable		—		301		2,757
		203,259		345,784		253,142
Bank debt (Note 6)		260,000		—		—
Senior term notes (Note 7)		191,582		198,594		213,246
Asset retirement obligations (Note 9)		22,437		18,006		17,329
Unrealized risk management loss (Note 15a (iii))		12,255		11,416		—
Future income taxes (Note 14b)		290,856		261,196		223,807
Non-controlling interest (Note 4)		69,711		71,537		(110	)
		1,050,100		906,533		707,414
Shareholders’ equity
Capital stock (Note 10b)		226,119		135,526		131,577
Contributed surplus (Note 11c)		7,611		3,840		760
Retained earnings		323,311		284,712		224,569
		557,041		424,078		356,906
	$	1,607,141	$	1,330,611	$	1,064,320

Commitments and contingent liabilities (Note 17)

On behalf of the Board
M.F. Belich (signed)	J.A. Thomson (signed)
Director	Director

See accompanying notes to the consolidated financial statements.

F-3

Compton Petroleum Corporation
Consolidated Statements of Earnings

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
(thousands of dollars, except per share data)	(unaudited)
Revenue
Oil and natural gas revenues	$	373,451		$	290,470		$	391,659		$	346,565		$	226,597
Royalties		(89,193	)		(67,929	)		(93,416	)		(82,566	)		(47,497	)
		284,258			222,541			298,243			263,999			179,100
Expenses
Operating		47,873			39,964			55,655			49,916			45,546
Transportation		7,740			6,059			8,595			8,447			8,167
General and administrative		14,359			10,335			15,215			12,206			9,845
Interest and finance charges (Note 8)		24,210			24,925			33,733			30,595			23,197
Depletion and depreciation		74,499			58,246			82,554			61,749			55,473
Foreign exchange (gain) loss (Note 7)		(7,006	)		(4,672	)		(14,631	)		(47,368	)		1,583
Accretion of asset retirement obligations (Note 9)		1,416			1,261			1,670			1,436			1,241
Stock-based compensation (Note 11c and d)		4,254			2,699			3,410			793			190
Risk management (gain) loss (Note 15a (iv))		36,110			10,587			8,808			4,132			(4,424	)
		203,455			149,404			195,009			121,906			140,818
Earnings before taxes and non-controlling interest		80,803			73,137			103,234			142,093			38,282
Income taxes(Note 14a)
Current		1,474			2,680			2,751			3,282			1,428
Future		31,056			21,795			33,432			20,041			18,542
		32,530			24,475			36,183			23,323			19,970
Earnings before non-controlling interest		48,273			48,662			67,051			118,770			18,312
Non-controlling interest (Note 4)		5,053			1,406			3,418			(110	)		—
Net earnings	$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Net earnings per share(Note 12)
Basic	$	0.35		$	0.40		$	0.54		$	1.02		$	0.16
Diluted	$	0.33		$	0.38		$	0.51		$	0.97		$	0.16

Consolidated Statements of Retained Earnings

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
(thousands of dollars)	(unaudited)
Retained earnings, beginning of period	$	284,712		$	224,569		$	224,569		$	112,039		$	96,093
Net earnings		43,220			47,256			63,633			118,880			18,312
Premium on redemption of shares (Note 10b)		(4,621	)		(1,352	)		(3,490	)		(6,350	)		(2,366	)
Retained earnings, end of period	$	323,311		$	270,473		$	284,712		$	224,569		$	112,039

See accompanying notes to the consolidated financial statements.

F-4

Compton Petroleum Corporation
Consolidated Statements of Cash Flow

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
(thousands of dollars)	(unaudited)
Operating activities
Net earnings	$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Amortization of deferred charges and other		1,447			1,596			2,101			2,208			1,367
Depletion and depreciation		74,499			58,246			82,554			61,749			55,473
Accretion of asset retirement obligations		1,416			1,261			1,670			1,436			1,241
Unrealized foreign exchange (gain) loss		(7,012	)		(4,703	)		(14,652	)		(47,388	)		1,583
Future income taxes		31,056			21,795			33,432			20,041			18,542
Unrealized risk management (gain) loss (Note 15a (iv))		34,930			6,084			2,179			—			—
Stock-based compensation		4,254			2,699			3,410			760			—
Asset retirement expenditures		(391	)		(91	)		(614	)		(2,683	)		(446	)
Non-controlling interest		5,053			1,406			3,418			(110	)		—
Cash flow from operations		188,472			135,549			177,131			154,893			96,072
Change in non-cash working capital (Note 16)		(3,368	)		(2,852	)		(12,594	)		1,318			(5,166	)
		185,104			132,697			164,537			156,211			90,906
Financing activities
Issuance (repayment) of bank debt		40,000			8,323			43,373			124,500			(190,000	)
Issuance of senior notes		—			—			—			—			259,050
Deferred financing charges		—			—			—			(128	)		(14,810	)
Proceeds from share issuances, net		89,421			2,772			3,258			6,400			18,177
Proceeds from partnership unit issuance		—			74,043			74,343			—			—
Distributions to partner		(6,879	)		(3,822	)		(6,114	)		—			—
Redemption of common shares		(5,328	)		(1,600	)		(4,005	)		(7,942	)		(3,026	)
Change in non-cash working capital (Note 16)		4,850			4,007			324			(1,387	)		3,514
		122,064			83,723			111,179			121,443			72,905
Investing activities
Property and equipment additions		(323,027	)		(205,482	)		(296,676	)		(222,055	)		(127,993	)
Corporate acquisitions (Note 3)		—			(6,441	)		(12,132	)		—			—
Property acquisitions		(17,199	)		(4,552	)		(20,830	)		(65,622	)		(44,857	)
Property dispositions		—			—			19,276			2,194			17,700
Change in non-cash working capital (Note 16)		39,890			(1,776	)		29,166			8,652			1,012
		(300,336	)		(218,251	)		(281,196	)		(276,831	)		(154,138	)
Change in cash		6,832			(1,831	)		(5,480	)		823			9,673
Cash,beginning of period		10,068			15,548			15,548			14,725			5,052
Cash,end of period	$	16,900		$	13,717		$	10,068		$	15,548		$	14,725

See accompanying notes to the consolidated financial statements.

F-5

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

1.	Significant accounting policies
	Compton Petroleum Corporation (the “Company” or “Compton”) is in the business of the exploration for and production of petroleum and natural gas reserves in the Western Canadian Sedimentary Basin.
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. Information prepared in accordance with accounting principles generally accepted in the United States is included in Note 19.
	The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries from their respective dates of acquisition. The consolidated financial statements also include the accounts of Mazeppa Processing Partnership in accordance with Accounting Guideline 15 (“AcG-15”) “Consolidation of Variable Interest Entities”, as outlined in Note 4.
	All amounts are presented in Canadian dollars unless otherwise stated.
b)	Measurement uncertainty
	The timely preparation of financial statements requires that Management make estimates and assumptions and use judgment regarding assets, liabilities, revenues and expenses. Such estimates relate primarily to transactions and events that have not settled as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.
	Amounts recorded for depletion and depreciation, asset retirement obligations and amounts used in impairment test calculations are based upon estimates of petroleum and natural gas reserves and future costs to develop those reserves. By their nature, these estimates of reserves, costs and related future cash flows are subject to uncertainty, and the impact on the consolidated financial statements of future periods could be material.
c)	Property and equipment

i) Capitalized costs

The Company follows the full cost method of accounting for its petroleum and natural gas operations as determined by the Canadian Institute of Chartered Accounts (“CICA”), Accounting Guideline 16 (“AcG-16”). 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, costs of drilling both producing and non-producing wells, production facilities, asset retirement costs and certain general and administrative expenses directly related to exploration and development activities.

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.

Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.

F-6

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

1. Significant accounting policies(continued)

ii)	Depletion and depreciation
	Depletion and depreciation of property and 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 until it is determined whether or not proved reserves are attributable to the properties or impairment has occurred. Estimated future costs to be incurred in developing proved reserves are included in costs subject to depletion. For depletion and depreciation purposes, relative volumes of 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 certain midstream facilities is provided for on a straight line basis over 30 years and depreciation of office equipment is provided for on a declining balance basis at 20% per annum.
iii)	Impairment test
	At each reporting period the Company performs an impairment test to determine the recoverability of capitalized costs associated with reserves. An impairment loss is recognized when the carrying amount of a cost centre exceeds its fair value. The carrying amount of the cost centre is not recoverable if the carrying amount exceeds the sum of the undiscounted cash flows from proved reserves plus the costs of unproved properties. If the sum of the cash flows is less than the carrying amount, the impairment loss is limited to the amount by which the carrying amount exceeds the sum of the fair value of proved and probable reserves and the costs of unproved properties that have been subject to a separate impairment test and contain no probable reserves.
iv)	Asset retirement obligations
	The Company recognizes the fair value of estimated asset retirement obligations on the consolidated balance sheet when a reasonable estimate of fair value can be made. Asset retirement obligations include those legal obligations where the Company will be required to retire tangible long-lived assets such as well sites, pipelines and facilities. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost. Asset retirement costs are amortized using the unit-of-production method and are included in depletion and depreciation in the consolidated statement of earnings. Increases in the asset retirement obligations resulting from the passage of time are recorded as accretion of asset retirement obligations in the consolidated statement of earnings.
v)	Inventories
	Physical inventory held for exploration, development and operating activities is included in property and equipment and is valued at cost.

F-7

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

1.	Significant accounting policies(continued)
d)	Goodwill
	Goodwill is recorded on a corporate acquisition when the purchase price is in excess of the fair values assigned to assets acquired and liabilities assumed. Goodwill is not amortized and an impairment test is performed at least annually to evaluate the carrying value. To assess impairment the fair value of the reporting unit is determined and compared to the carrying value. If fair value is less than the carrying value then a second test is performed to determine the amount of the impairment. Any loss recognized is equal to the difference between the implied fair value and the carrying value of the goodwill.
e)	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 except as disclosed in Note 15b)ii).
	The Company uses financial instruments for non-trading purposes to manage fluctuations in commodity prices, foreign currency exchange rates and interest rates, as described in Note 15. The Company has elected not to designate any of its current risk management activities as accounting hedges and accounts for all derivative financial instruments using the mark-to-market accounting method.
f)	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.
g)	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. The liability for future income taxes is increased and capital stock is reduced by the estimated tax benefits transferred to shareholders at the time the resource expenditure deductions are renounced.
h)	Earnings per share amounts
	The Company uses the treasury stock method to determine the dilutive effect of stock options. This method assumes that proceeds received from the exercise of in-the-money stock options are used to repurchase common shares at the average market price for the period. Basic net earnings per common share are determined by dividing net earnings by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed by giving effect to the potential dilution that would occur if stock options were exercised.
i)	Income taxes
	Income taxes are recorded using the liability method of accounting. Future income taxes are calculated based on the difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Changes in income tax rates that are substantively enacted are reflected in the accumulated future income tax balances in the period the change occurs.

F-8

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

1.	Significant accounting policies(continued)
j)	Revenue recognition
	Revenue associated with the production and sale of crude oil, natural gas and natural gas liquids owned by the Company is recognized when the purchaser takes possession of the commodity product. Other revenue is recognized in the period that the service is provided to the customer.
k)	Stock-based compensation plan
	The Company has stock-based compensation plans which include stock options and an employee stock savings plan.
	The Company records compensation expense in the consolidated statements of earnings for stock options granted to Directors, Officers and employees using the fair-value method. Compensation costs are recognized over the vesting period. Fair values are determined using the Black-Scholes option pricing model.
	The Company matches employee contributions to the stock savings plan and these cash payments are recorded as compensation expense as incurred.
l)	Deferred financing charges
	Financing costs related to the issuance of the senior term notes have been deferred and are amortized over the term of the notes on a straight-line basis.
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.
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)	Defined benefit pension plan
	The Company accrues for obligations under a defined benefit pension plan and the related costs, net of plan assets. The cost of the pension is actuarially determined using the projected benefit method based on length of service and reflects Management’s best estimate of expected plan investment performance, salary escalation and retirement age of employees.
p)	Reclassification
	Certain information provided for prior years has been reclassified to conform with the current period presentation.

F-9

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

2. Changes in accounting policy

Hedging relationships

On January 1, 2004, the Company adopted the amendments made to the CICA modified Accounting Guideline 13 (“AcG-13”) “Hedging Relationships” and Emerging Issues Committee Abstract 128 (“EIC 128”), “Accounting for Trading, Speculative or Non Trading Derivative Financial Instruments”. Derivative instruments that do not qualify for hedge accounting or are not designated as hedges, are recorded on the balance sheet as either an asset or liability with changes in fair value recognized in earnings.

The Company has elected not to designate any of its risk management activities in place at December 31, 2003 as accounting hedges under AcG-13 and accordingly, accounts for all derivative financial instruments using the mark-to-market accounting method. The impact on the Company’s consolidated financial statements at January 1, 2004 was the recognition of an unrealized hedge liability of $10.9 million and a deferred risk management loss of $10.9 million, before tax. The deferred risk management loss is charged to earnings as the contracts are settled and the liability is re-valued at each balance sheet date with any gain or loss recognized in earnings.

3. Business combinations

On April 12, 2004 and November 15, 2004, respectively, the Company acquired 100% of the issued and outstanding shares of Redwood Energy, Ltd. and Mayfair Energy Ltd. for total cash consideration of $12.1 million plus the assumption of $12.1 million of debt. Both were independent exploration and production companies with operations in the Company’s core areas.

The business combinations have been accounted for using the purchase method with results of operations included in the consolidated financial statements from the date of acquisition. Goodwill recognized on these transactions amounted to $7.9 million.

During the year ended December 31, 2004, both companies were wound up into Compton Petroleum Corporation and dissolved.

4. Non-controlling interest

Mazeppa Processing Partnership (“MPP” or “the Partnership”) is a limited partnership organized under the laws of the province of Alberta and owns certain midstream facilities, including gas plants and pipelines in Southern Alberta. The Company processes a significant portion of its production from the area through these facilities pursuant to a processing agreement with MPP. The Company does not have an ownership position in MPP, however, the Company, through a management agreement, manages the activities of MPP and is considered to be the primary beneficiary of MPP’s operations. Pursuant to AcG-15, these consolidated financial statements include the assets, liabilities and operations of the Partnership. Equity in the Partnership, attributable to the partners of MPP, is recorded on consolidation as a non-controlling interest and is comprised of the following:

F-10

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

4. Non-controlling interest(continued)

	As at
	September 30,			As at December 31,
	2005			2004			2003
Non-controlling interest, beginning of period	$	71,537		$	(110	)	$	—
Proceeds from issue of partnership units, net		—			74,343			—
Earnings (loss) attributable to non-controlling interest		5,053			3,418			(110	)
Distributions to limited partner		(6,879	)		(6,114	)		—
Non-controlling interest, end of period	$	69,711		$	71,537		$	(110	)

Commencing May 1, 2004, pursuant to the terms of a processing agreement between Compton and MPP, Compton pays a monthly fee to MPP for the transportation and processing of natural gas through the MPP owned facilities. The fee is comprised of a fixed base fee of $764 thousand per month plus MPP operating costs, net of third party revenues. These amounts are eliminated from revenues and expenses on consolidation.

The processing agreement has a five year term ending April 1, 2009, at which time Compton may renew the agreement under terms determined at that time or purchase the Partnership units for the predetermined amount of $55 million, deemed to be fair value. In the event that the Company does not renew the processing agreement nor exercise the purchase option, the Limited Partner may dispose of the Partnership units to an independent third party.

MPP has guaranteed payment of certain obligations of its limited partner under a credit agreement between the limited partner and a syndicate of lenders. The maximum liability of the Partnership under the guarantee is limited to amounts due and payable to MPP by the Company pursuant to the processing agreement. The maximum liability at September 30, 2005 was $32.9 million (December 31, 2004 — $39.7 million) payable over the remaining term of the processing agreement. The Company has determined that its exposure to loss under these arrangements is minimal, if any.

5. Property and equipment

	As at September 30, 2005
			Accumulated
			depletion
			and
	Cost		depreciation			Net
Exploration and development costs	$	1,427,534	$	(341,444	)	$	1,086,090
Production equipment and processing facilities		390,630		(47,646	)		342,984
Inventory		6,060		—			6,060
Future asset retirement costs		12,591		(3,602	)		8,989
Office equipment		7,459		(3,899	)		3,560
	$	1,844,274	$	(396,591	)	$	1,447,683

F-11

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

5. Property and equipment(continued)

	As at December 31, 2004
			Accumulated
			depletion
			and
	Cost		depreciation			Net
Exploration and development costs	$	1,161,396	$	(281,614	)	$	879,782
Production equipment and processing facilities		317,477		(34,150	)		283,327
Inventory		6,187		—			6,187
Future asset retirement costs		9,576		(3,111	)		6,465
Office equipment		6,005		(3,216	)		2,789
	$	1,500,641	$	(322,091	)	$	1,178,550

	As at December 31, 2003
			Accumulated
			depletion
			and
	Cost		depreciation			Net
Exploration and development costs	$	931,970	$	(212,223	)	$	719,747
Production equipment and processing facilities		231,918		(21,411	)		210,507
Inventory		2,246		—			2,246
Future asset retirement costs		10,557		(3,422	)		7,135
Office equipment		5,143		(2,475	)		2,668
	$	1,181,834	$	(239,531	)	$	942,303

Employee salaries and insurance costs of $5.9 million at September 30, 2005 (December 31, 2004 - $4.6 million, 2003 — $4.0 million) directly related to exploration and development activities are capitalized. No other general and administrative costs are capitalized.

As at September 30, 2005 future capital expenditures of $48.9 million (2004 — $34.0 million), relating to the development of proved reserves have been included in costs subject to depletion. At year end December 31, 2004, the costs incurred, as estimated by independent engineers, were $89.1 million (2003 — $62.4 million, 2002 — $37.5 million).

Undeveloped properties with a cost at September 30, 2005 of $248.2 million (2004 — $159.4 million) and at December 31, 2004 of $187.8 million (2003 — $161.9 million, 2002 — $155.0 million) included in exploration and development costs, have not been subject to depletion.

F-12

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

5. Property and equipment(continued)

The prices used in the impairment test evaluation of the Company’s natural gas, crude oil and natural gas liquids reserves were:

	Natural
As at December 31, 2004	gas		Oil		NGL
	$ per mcf		$ per bbl		$ per bbl
2005	$	7.03	$	46.13	$	42.67
2006	$	6.77	$	43.75	$	40.28
2007	$	6.57	$	40.60	$	36.64
2008	$	6.24	$	38.05	$	34.14
2009	$	6.04	$	36.33	$	32.52
Approximate % increase thereafter		1.5		1.5		1.5

6. Credit facilities

	As at
	September 30,		As at December 31,
	2005		2004		2003
Authorized	$	274,000	$	240,000	$	185,000
Prime rate	$	8,100	$	3,000	$	21,000
Bankers’ Acceptance		251,900		217,000		143,500
Utilized	$	260,000	$	220,000	$	164,500

As of September 30, 2005, the Company had arranged authorized senior credit facilities with a syndicate of Canadian banks in the amount of $274 million. Advances under the facilities can be drawn and currently bear interest as follows:

Prime rate plus 0.15%
Bankers’ Acceptance rate plus 1.15%
LIBOR rate plus 1.15%

Margins are determined based on the ratio of total consolidated debt to consolidated cash flow. Subsequent to September 30, 2005, the facilities were increased to $289 million. The facilities reach term on July 5, 2006 and mature 366 days later on July 6, 2007. Consequently, they have been re-classified as long-term liabilities at September 30, 2005.

The senior credit facilities are secured by a first fixed and floating charge debenture in the amount of $600 million covering all the Company’s assets and undertakings.

F-13

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

7. Senior term notes

	As at
	September 30,			As at December 31,
	2005			2004			2003
Senior term notes (US$165.0 million)
Proceeds on issuance	$	259,051		$	259,051		$	259,051
Cumulative unrealized foreign exchange gain		(67,469	)		(60,457	)		(45,805	)
	$	191,582		$	198,594		$	213,246

The senior term notes bear interest at 9.90%, semi-annual, with principal repayable on May 15, 2009 and are subordinate to the Company’s bank credit facilities.

The notes are not redeemable prior to May 15, 2006, except in limited circumstances. After that time, they can be redeemed in whole or part, at the rates indicated below:

May 15, 2006	104.950	%
May 15, 2007	102.475	%
May 15, 2008 and thereafter	100.000	%

Subsequent to September 30, 2005, as discussed in Note 18a) to these consolidated financial statements, the Company, through its wholly owned subsidiary Compton Petroleum Holdings Corporation, purchased US$158.25 million of these 9.90% senior term notes pursuant to a tender offer which expired on November 29, 2005.

The Company entered into a cross currency, interest rate swap arrangement with its banking syndicate whereby interest paid by the Company on the US$165.0 million principal amount is based upon the 90 day Bankers’ Acceptance rate plus 4.85%, calculated on the $259.0 million proceeds of issuance. This arrangement resulted in an effective interest rate of 7.58% during period ended September 30, 2005 (December 31, 2004 — 7.24%, 2003 — 7.85%) net of gains realized on the swap arrangement, see Note 15a)iv).

The unrealized foreign exchange gain recognized for the nine month period ended September 30, 2005 was $7.0 million (December 31, 2004 — $14.6 million gain), and the accumulated unrealized gain to September 30, 2005 is $67.5 million.

8. Interest and finance charges

Amounts charged to expense during the year ended are as follows:

	Nine months ended
	September 30,				Years ended December 31,
	2005		2004		2004		2003		2002
Interest on bank debt, net	$	7,159	$	6,959	$	9,662	$	6,611	$	5,339
Interest on senior term notes		15,318		15,807		21,281		21,711		15,932
Finance charges		1,733		2,159		2,790		2,273		1,926
Total	$	24,210	$	24,925	$	33,733	$	30,595	$	23,197

Finance charges include the amortization of deferred charges and current year expenses.

F-14

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

9. Asset retirement obligations

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations associated with the retirement of oil and natural gas assets:

	As at
	September 30,			As at December 31,
	2005			2004			2003
Asset retirement obligations, beginning of period	$	18,006		$	17,329		$	17,335
Liabilities incurred		3,928			3,357			1,241
Liabilities settled and disposed		(913	)		(4,350	)		(2,683	)
Accretion expense		1,416			1,670			1,436
Asset retirement obligations, end of period	$	22,437		$	18,006		$	17,329

At September 30, 2005, the total undiscounted amount of estimated cash flows required to settle the obligations is $169.0 million (December 31, 2004 — $148.9 million, 2003 — $135.1 million), which has been discounted using a credit-adjusted risk free rate of 10.7%. The majority of these obligations are not expected to be settled for several years or decades into the future. Settlements will be funded from general Company resources at the time of retirement and removal.

10.	Capital stock
a)	Authorized
	The Company is authorized to issue an unlimited number of common shares and an unlimited number of preferred shares, issuable in series.
b)	Issued and outstanding

	Nine months ended						Years ended December 31,
	September 30, 2005						2004						2003
	Number						Number						Number
	of						of						of
	Shares			Amount			Shares			Amount			Shares			Amount
	(000s)						(000s)						(000s)
Common shares outstanding, beginning of period		117,354		$	135,526			116,423		$	131,577			116,271		$	128,079
Shares issued for cash, net		7,500			87,294			—			—			587			2,712
Shares issued for property		—			—			110			875			15			81
Shares issued under stock Option plan		2,823			4,006			1,271			3,589			913			2,296
Shares repurchased		(464	)		(707	)		(450	)		(515	)		(1,363	)		(1,591	)
Common shares outstanding, end of period		127,213		$	226,119			117,354		$	135,526			116,423		$	131,577

F-15

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

10. Capital stock(continued)

In February 2005, the Company issued 7,500,000 common shares for gross proceeds of $90.0 million before underwriters’ fees and issue expenses of $4.1 million.

On March 15, 2005, the Company received regulatory approval for a new Normal Course Issuer Bid commencing March 17, 2005 and ending on March 16, 2006. Under the bid, the Company may purchase for cancellation up to 6,200,000 of its common shares, representing approximately 5.0% of the issued and outstanding common shares as of March 9, 2005.

During the nine months ended September 30, 2005, the Company purchased for cancellation 463,900 common shares at an average price of $11.49 per share (December 31, 2004 – 450,100 common shares at an average price of $8.90 per share, December 31, 2003 – 1,363,400 shares at an average price of $5.83 per share) pursuant to the normal course issuer bid. The excess of the purchase price over book value has been charged to retained earnings.

c) Shareholder rights plan

The Company has a shareholder rights plan (the “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 common shares at a 50% discount to the market price at that time.

11. Stock-based compensation plans

a) Stock option plan

The Company has implemented a stock option plan for Directors, Officers and employees. The exercise price of each option approximates the market price for the common shares on the date the option was granted. Options granted under the plan before June 1, 2003 are generally fully exercisable after four years and expire ten years after the grant date. Options granted under the plan after June 1, 2003 are generally fully exercisable after four years and expire five years after the grant date.

F-16

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

11. Stock-based compensation plans(continued)

The following tables summarize the information relating to stock options:

	As at September 30,					As at December 31,
	2005					2004					2003
				Weighted					Weighted					Weighted
				average					average					average
	Stock			exercise		Stock			exercise		Stock			exercise
	options			price		options			price		options			price
	(000s)					(000s)					(000s)
Outstanding, beginning of period		11,655		$	3.51		10,672		$	2.54		10,357		$	2.21
Granted		2,769		$	11.77		2,549		$	7.34		1,503		$	5.18
Exercised		(2,823	)	$	1.25		(1,271	)	$	2.56		(913	)	$	2.52
Cancelled		(177	)	$	8.11		(295	)	$	5.26		(275	)	$	4.63
Outstanding, end of period		11,424		$	6.01		11,655		$	3.51		10,672		$	2.54
Exercisable, end of period		6,144		$	3.29		7,812		$	2.19		7,763		$	1.77

The range of exercise prices of stock options outstanding and exercisable at September 30, 2005 are as follows:

	Outstanding Options						Exercisable Options
			Weighted
			average		Weighted				Weighted
	Number of		remaining		average		Number of		average
	options		contractual		exercise		options		exercise
Range of exercise prices	outstanding		life (years)		price		outstanding		price
	(000s)						(000s)
$0.80 - $2.99		2,694		2.9	$	1.55		2,694	$	1.55
$3.00 - $3.99		1,529		5.6	$	3.46		1,248	$	3.40
$4.00 - $4.99		1,605		6.4	$	4.30		1,217	$	4.24
$5.00 - $6.99		1,218		3.2	$	5.87		545	$	5.91
$7.00 - $9.99		1,499		3.6	$	7.61		416	$	7.55
$10.00 - $12.99		2,707		4.5	$	11.58		9	$	10.76
$13.00 - $15.05		172		4.9	$	13.58		15	$	13.44
		11,424		4.3	$	6.01		6,144	$	3.29

F-17

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

11. Stock-based compensation plans(continued)

The range of exercise prices of stock options outstanding and exercisable at December 31, 2004 are as follows:

	Outstanding Options						Exercisable Options
			Weighted
			average		Weighted				Weighted
	Number of		remaining		average		Number of		average
	options		contractual		exercise		options		exercise
Range of exercise prices	outstanding		life (years)		price		outstanding		price
	(000s)						(000s)
$0.60 - $0.99		2,875		1.8	$	0.64		2,875	$	0.64
$1.00 - $2.99		2,168		4.1	$	1.73		2,166	$	1.73
$3.00 - $3.99		1,702		6.3	$	3.43		1,279	$	3.32
$4.00 - $4.99		1,799		7.1	$	4.29		992	$	4.19
$5.00 - $6.99		1,335		4.0	$	5.86		392	$	5.89
$7.00 - $10.80		1,776		4.4	$	7.88		108	$	7.58
		11,655		4.3	$	3.51		7,812	$	2.19

b) Stock options granted prior to January 1, 2003

The Company has not recorded stock-based compensation expense in the consolidated statements of earnings related to stock options granted prior to 2003. If the Company had applied the fair-value method to options granted prior to 2003, the Company’s pro-forma net earnings and net earnings per share would have been as indicated below:

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
Net earnings
As reported	$	43,220		$	47,256		$	63,633		$	118,880		$	18,312
Less fair value of stock options		(749	)		(1,162	)		(1,545	)		(2,317	)		(3,317	)
Pro-forma	$	42,471		$	46,094		$	62,088		$	116,563		$	14,995
Net earnings per common share — basic
As reported	$	0.35		$	0.40		$	0.54		$	1.02		$	0.16
Pro-forma	$	0.34		$	0.39		$	0.53		$	1.00		$	0.13
Net earnings per common share — diluted
As reported	$	0.33		$	0.38		$	0.51		$	0.97		$	0.16
Pro-forma	$	0.32		$	0.37		$	0.50		$	0.95		$	0.13

F-18

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

11. Stock-based compensation plans(continued)

c) Stock options granted after January 1, 2003

The Company has recorded stock-based compensation expense in the consolidated statement of earnings for stock options granted to Directors, Officers and employees after January 1, 2003 using the fair value method.

The fair value of each option granted is estimated on the date of grant using the Black-Scholes option pricing model with weighted average assumptions for grants as follows:

	Nine months ended						Years ended
	September 30,						December 31,
	2005			2004			2004			2003
Weighted average fair value of options granted	$	5.39		$	3.57		$	3.70		$	3.01
Risk-free interest rate		3.6	%		3.9	%		3.9	%		4.3	%
Expected life (years)		5.0			5.0			5.0			6.1
Expected volatility		43.9	%		49.9	%		49.6	%		56.0	%

The following table presents the reconciliation of contributed surplus with respect to stock-based compensation:

	As at
	September 30,			As at December 31,
	2005			2004			2003
Contributed surplus, beginning of period	$	3,840		$	760		$	—
Stock-based compensation expense		4,254			3,410			760
Stock options exercised		(483	)		(330	)		—
Contributed surplus, end of period	$	7,611		$	3,840		$	760

d) Share appreciation rights plan

CICA Handbook section 3870 requires recognition of compensation costs with respect to changes in the intrinsic value for the variable component of fixed share appreciation rights (“SARs”). During the periods ended September 30, 2005 and 2004 and the year ended December 31, 2004, there were no significant compensation costs related to the outstanding variable component of these SARs, at December 31, 2003, $33,000 (2002 — $190,000) was included in earnings. The liability related to the variable component of these SARs amounts to $1.5 million, which is included in accounts payable as at September 30, 2005 (December 31, 2004 — $1.7 million, 2003 — $2.4 million). All outstanding SARs having a variable component expire at various times through 2011.

F-19

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

12. Per share amounts

The following table summarizes the common shares used in calculating net earnings per common share:

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
		(000s	)		(000s	)		(000s	)		(000s	)		(000s	)
Weighted average common shares outstanding — basic		125,083			117,183			117,244			116,267			113,428
Effect of stock options		5,831			6,439			6,789			5,856			4,572
Weighted average common shares outstanding — diluted		130,914			123,622			124,033			122,123			118,000

In calculating diluted earnings per common share for the period ended September 30, 2005, the Company excluded 590,000 options (September 30, 2004 — 193,500, year ended December 31, 2004 - 288,000, 2003 — 615,100 and 2002 — 2,193,662), as the exercise price was greater than the average market price of its common shares in those years.

13. Defined benefit pension plan

Substantially all of the employees of MPP are enrolled in a co-sponsored, defined benefit pension plan. The Company does not have a pension plan for other employees. Information relating to the MPP retirement plan is outlined below:

	As at December 31,
	2004			2003
Accrued benefit obligation	$	5,855		$	5,331
Fair value of plan assets	$	5,221		$	4,488
Funded status
Plan assets less than benefit obligation	$	(634	)	$	(843	)
Unamortized net actuarial gain		(269	)		(221	)
Unamortized past service costs		933			1,000
Accrued benefit (liability), included in deferred financing charges and other	$	30		$	(64	)

F-20

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

13. Defined benefit pension plan(continued)

Economic assumptions used to determine benefit obligation and periodic expense are:

	Years ended December 31,
	2004			2003
Discount rate		6.3	%		6.3	%
Expected rate of return on assets		7.0	%		7.0	%
Rate of compensation increase		4.5	%		4.0	%
Average remaining service period of covered employees	15 years			15 years

Actuarial evaluations are required every three years, the most recent being January 1, 2003.

Pension expense, included in MPP operating costs, is as follows:

	Years ended December 31,
	2004			2003
Current service cost	$	190		$	111
Interest on accrued benefit obligation		336			173
Interest on assets		(333	)		(152	)
Amortization on past service cost		67			37
Pension expense	$	260		$	169

MPP expects to contribute $354 thousand to the plan in 2005. Contributions by the participants to the pension plan were $66 thousand for the year ended December 31, 2004.

F-21

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

14. Income taxes

a) The following table reconciles income taxes calculated at the Canadian statutory rate with actual income taxes:

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
Earnings before taxes and non-controlling interest	$	80,803		$	73,137		$	103,234		$	142,093		$	38,282
Canadian statutory rate		37.6	%		38.6	%		38.6	%		40.6	%		42.1	%
Expected income taxes	$	30,382		$	28,231		$	39,848		$	57,690		$	16,117
Effect on taxes resulting from:
Non-deductible crown charges		10,568			14,549			17,611			23,922			17,103
Resource allowance		(7,901	)		(10,822	)		(13,535	)		(16,485	)		(14,471	)
Non-deductible stock-based compensation		1,601			1,042			1,316			309			—
Federal capital tax		1,444			1,900			2,526			2,497			1,428
Statutory tax rate reductions		(1,908	)		(8,359	)		(8,359	)		(37,130	)		(1,340	)
Non-taxable portion of foreign exchange (gain) loss		(1,319	)		(909	)		(2,831	)		(8,202	)		334
Other		(337	)		(1,157	)		(393	)		722			799
Provision for income taxes	$	32,530		$	24,475		$	36,183		$	23,323		$	19,970
Current
Income taxes	$	30		$	780		$	225		$	785		$	—
Federal capital taxes		1,444			1,900			2,526			2,497			1,428
Future		31,056			21,795			33,432			20,041			18,542
	$	32,530		$	24,475		$	36,183		$	23,323		$	19,970
Effective tax rate		40.3	%		33.5	%		35.0	%		16.4	%		52.2	%

A significant portion of the Company’s taxable income is generated by a partnership. Income taxes are incurred on the partnership’s taxable income in the year following its inclusion in the Company’s consolidated net earnings. Current income tax will vary and is dependent upon the amount of capital expenditures incurred and the method of deployment.

In 2004, the Government of Alberta introduced legislation to reduce its corporate income tax rate from 12.5% to 11.5% and retain the resource allowance and non-deductible crown royalties regime until 2007.

F-22

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

14. Income taxes(continued)

b) The net future income tax liability is comprised of:

	As at
	September 30,			As at December 31,
	2005			2004			2003
Future income tax liabilities
Property and equipment in excess of tax values	$	230,353		$	199,931		$	169,855
Timing of partnership items		76,903			67,089			62,975
Foreign exchange gain on long-term debt		11,346			10,169			7,934
Future income tax assets
Attributed Canadian royalty income		(6,857	)		(9,015	)		(9,667	)
Asset retirement obligations		(7,546	)		(6,057	)		(6,024	)
Non-capital losses carried forward		—			(53	)		(789	)
Other		(13,343	)		(868	)		(477	)
Net future income tax liability	$	290,856		$	261,196		$	223,807

15. Financial instruments

a) Derivative financial instruments and risk management activities

The Company is exposed to risks from fluctuations in commodity prices, interest rates and Canada/US currency exchange rates. The Company utilizes various derivative financial instruments for non-trading purposes to manage and mitigate its exposure to these risks. As outlined in Note 2, effective January 1, 2004, the Company elected to account for all derivative financial instruments using the mark-to-market method.

Risk management activities during the periods, utilizing derivative instruments, relate to commodity price hedges and cross currency interest rate swap arrangements and are summarized below:

i) Commodity price hedges

The Company enters into hedge transactions relating to crude oil and natural gas prices to mitigate volatility in commodity prices and the resulting impact on cash flow. The contracts entered into are forward transactions providing the Company with a range of prices on the commodities sold. Outstanding hedge contracts at September 30, 2005 and December 31, 2004 are:

F-23

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

15.	Financial instruments(continued)
	As at September 30, 2005

		Daily
		Notional	Prices	Mark-
Commodity	Term	Volume	Received	to-Market
Natural gas
Collar	Apr. 1 - Oct. 31/05	52,381 mcf	$6.68 - $9.40/mcf	$	(3,393	)
Collar	Nov. 1/05 - Mar. 31/06	38,095 mcf	$8.66 - $12.50/mcf		(13,522	)
Fixed	Nov. 1/05 - Mar. 31/06	9,524 mcf	$9.03/mcf		(7,403	)
Collar	Apr. 1/06 - Oct. 31/06	19,048 mcf	$8.14/mcf - $12.18/mcf		(2,921	)
					(27,239	)
Crude Oil
Collar	Jan. 1 - Dec. 31/05	1,500 bbls	US$37.67 - $49.00/bbl		(2,774	)
Collar	Jan. 1 - Dec. 31/06	2,000 bbls	US$55.00 - $76.25/bbl		(860	)
					(3,634	)
Unrealized risk management loss				$	(30,873	)

As at December 31, 2004

		Daily
		Notional	Prices	Mark-
Commodity	Term	Volume	Received	to-Market
Natural Gas – Collar	Jan. 1 - Mar. 31/05	23,810 mcf	$7.51 - $11.56/mcf	$	2,348
Crude oil – Collar	Jan. 1 - Dec. 31/05	1,000 bbls	US$35.00 - $48.75/bbl		(363	)
Unrealized risk management gain				$	1,985

ii) Deferred risk management loss

As at January 1, 2004, the Company elected not to designate any of its risk management activities as accounting hedges under Accounting Guideline 13 and accordingly accounts for all derivative instruments using the mark-to-market method. As a result, on January 1, 2004, the Company recorded a liability and a deferred risk management loss of $10.9 million relating to then outstanding commodity hedges and the interest rate swap. During the period ended September 30, 2005, $1.2 million (December 31, 2004 — $3.6 million) of the deferred loss was charged to earnings. The remaining balance of $6.0 million at September 30, 2005 (December 31, 2004 — $7.3 million) relates to the interest rate swap and will be charged to earnings in annual amounts of $1.6 million until eliminated in 2009.

F-24

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

15. Financial instruments(continued)

iii) Cross currency interest rate swap

Concurrent with the closing of the senior notes offering, the Company entered into interest rate swap arrangements with its banking syndicate that convert fixed rate U.S. dollar denominated interest obligations into floating rate Canadian dollar denominated interest obligations. At September 30, 2005, the Company valued the liability relating to future unrealized losses on the swap arrangements to be $12.3 million (December 31, 2004 — $11.4 million) on a mark-to-market basis.

iv) Risk management (gains) losses

Risk management (gains) and losses recognized during the periods relating to the above are summarized below:

	Nine months ended September 30, 2005
	Commodity		Interest
	Contracts		Rate Swap			Total
Unrealized
Amortization of deferred loss	$	—	$	1,231		$	1,231
Change in fair value		32,858		841			33,699
		32,858		2,072			34,930
Realized
Cash settlements		1,803		(623	)		1,180
Total (gain) loss	$	34,661	$	1,449		$	36,110

	Nine months ended September 30, 2004
	Commodity		Interest
	Contracts		Rate Swap			Total
Unrealized
Amortization of deferred loss	$	1,501	$	1,231		$	2,732
Change in fair value		2,673		679			3,352
		4,174		1,910			6,084
Realized
Cash settlements		6,208		(1,705	)		4,503
Total loss	$	10,382	$	205		$	10,587

F-25

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

15. Financial instruments(continued)

	Year ended December 31, 2004
	Commodity			Interest
	Contracts			Rate Swap			Total
Unrealized
Amortization of deferred loss	$	2,001		$	1,642		$	3,643
Change in fair value		(3,986	)		2,522			(1,464	)
		(1,985	)		4,164			2,179
Realized
Cash settlements		9,151			(2,522	)		6,629
Total loss	$	7,166		$	1,642		$	8,808

Risk management (gains) losses of $4.1 million and ($4.4) million for years ended December 31, 2003 and 2002 respectively reflect realized (gains) and losses recognized under hedge accounting.

b) Other financial instruments and risk

i) Credit risk management

Accounts receivable include amounts receivable for oil and natural 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 financial instruments. The Company deals with major institutions and believes these risks are minimal.

ii) Fair value of financial assets and liabilities

Other than its senior term notes, the fair values of the Company’s financial assets and liabilities that are included in the Company’s consolidated balance sheet as at September 30, 2005, approximate their carrying value. The estimated fair value of senior term notes is $204.3 million as at September 30, 2005 (December 31, 2004 — $218.5 million, 2003 — $231.6 million) based upon market information.

iii) Foreign currency 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 certain 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. During 2003, a gain of $2.5 million was realized and included in revenue (2002 — $0.4 million). At December 31, 2003, all swaps expired and the Company has not entered into any new arrangements.

F-26

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

16. Cash flow

Changes in non-cash working capital items increased (decreased) cash as follows:

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
Accounts receivable and other	$	(5,229	)	$	(9,950	)	$	(20,176	)	$	(16,593	)	$	1,312
Accounts payable		46,902			11,730			39,598			23,635			(2,608	)
Taxes payable		(301	)		(2,401	)		(2,526	)		1,541			656
	$	41,372		$	(621	)	$	16,896		$	8,583		$	(640	)
Operating activities
Accounts receivable and other	$	(9,725	)	$	(11,366	)	$	(19,309	)	$	(3,675	)	$	(6,480	)
Accounts payable		6,658			10,915			9,241			3,452			658
Taxes payable		(301	)		(2,401	)		(2,526	)		1,541			656
		(3,368	)		(2,852	)		(12,594	)		1,318			(5,166	)
Financing activities
Accounts receivable and other		(20	)		(76	)		367			(467	)		—
Accounts payable		4,870			4,083			(43	)		(920	)		3,514
		4,850			4,007			324			(1,387	)		3,514
Investing activities
Accounts receivable and other		4,516			1,491			(1,233	)		(12,451	)		7,792
Accounts payable		35,374			(3,267	)		30,399			21,103			(6,780	)
		39,890			(1,776	)		29,166			8,652			1,012
	$	41,372		$	(621	)	$	16,896		$	8,583		$	(640	)

Amounts paid during the year relating to interest expense and capital taxes are as follows:

	Nine months ended
	September 30,				Years ended December 31,
	2005		2004		2004		2003		2002
Interest paid	$	18,194	$	15,936	$	28,604	$	26,923	$	15,042
Current income taxes paid		2,070		2,345		4,952		1,485		1,084
	$	20,264	$	18,281	$	33,556	$	28,408	$	16,126

F-27

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

17. Commitments and contingent liabilities

a) Commitments

As at December 31, 2004, the Company has committed to certain payments over the next five years, as follows:

	2005		2006		2007		2008		2009
Operating leases	$	5,025	$	10,985	$	4,548	$	—	$	—
Office rent		1,268		1,356		249		—		—
MPP partnership distributions		9,172		9,172		9,172		9,172		3,057
Senior notes (US$165 million)		—		—		—		—		198,594
Other		136		243		—		—		—
	$	15,601	$	21,756	$	13,969	$	9,172	$	201,651

b) Legal proceedings

The Company is involved in various legal claims associated with normal operations. These claims, although unresolved at the current time, in management’s opinion, are minor in nature and are not expected to have a material impact on the financial position or results of operations of the Company.

18. Subsequent events

a) On November 22, 2005, by way of an Offering Circular, the Company sold by private placement, 7⁵/₈% US$300 million aggregate principal amount of Senior Notes due 2013 (the “Initial Notes”). The Company has used the net proceeds from the sale of the Initial Notes to fund the purchase by Compton Petroleum Holdings Corporation of US$158.25 million aggregate principal amount of the Company’s 9.90%, US$165 million, senior term notes that were tendered pursuant to the tender offer commenced on October 31, 2005. The Company intends to use the remaining net proceeds from the sale of the Initial Notes to repay a portion of the debt outstanding under its senior credit facilities. The tender offer expired on November 29, 2005.

b) On December 23, 2005, the Company filed a short form prospectus with the Alberta Securities Commission and a registration statement with the United States Securities and Exchange Commission to offer exchange notes (the “Exchange Notes”) for the Initial Notes. The terms of the Exchange Notes are substantially identical to the Initial Notes, except the Exchange Notes will be freely tradable in the United States by persons who are not affiliated with the Company.

F-28

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19. United States accounting principles and reporting

Reconciliation of consolidated financial statements to United States generally accepted accounting principles

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 flows, are described below.

Reconciliation of Net Earnings under Canadian GAAP to U.S. GAAP:

	Nine months ended
	September 30,				Years ended December 31,
	2005		2004		2004		2003			2002
										(restated
										note f)
Net earnings for period, as reported	$	43,220	$	47,256	$	63,633	$	118,880		$	18,312
Adjustments
Accretion of asset retirement obligations (Note h)		—		—		—		—			1,241
Depreciation and depletion (Note h)		—		—		—		—			542
Site restoration provision (Note h)		—		—		—		—			(1,072	)
Related income taxes (Note h)		—		—		—		—			(225	)
Accounting for income taxes (Note d)		—		—		—		(743	)		(5,402	)
Risk management gain (loss), net (Note f)		758		2,058		2,236		(14,425	)		8,659
Net earnings before change in accounting principle — U.S. GAAP		43,978		49,314		65,869		103,712			22,055
Cumulative effect of change in accounting principle, net (Note h)		—		—		—		(5,681	)		—
Net earnings — U.S. GAAP	$	43,978	$	49,314	$	65,869	$	98,031		$	22,055

F-29

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19. United States accounting principles and reporting(continued)

Consolidated Statements of Earnings — U.S. GAAP

	Nine months ended
	September 30, 2005						Years ended December 31,
	2005			2004			2004			2003			2002
Revenue, net of royalties	$	284,258		$	222,541		$	298,243		$	263,999		$	179,100
Expenses
Operating		47,873			39,964			55,655			49,916			45,546
Transportation		7,740			6,059			8,595			8,447			8,167
General and administrative		14,359			10,335			15,215			12,206			9,845
Interest and finance charges		24,210			24,925			33,733			30,595			23,197
Depletion and depreciation (Note h)		74,499			58,246			82,554			61,749			54,931
Foreign exchange (gain) loss		(7,006	)		(4,672	)		(14,631	)		(47,368	)		1,583
Accretion of asset retirement obligations (Note h)		1,416			1,261			1,670			1,436			1,072
Stock-based compensation		4,254			2,699			3,410			793			190
Risk management (gain) loss (Note f)		34,879			7,854			5,165			28,428			(13,083	)
Net earnings before taxes and non-controlling interest		82,034			75,870			106,877			117,797			47,652
Income tax expense (Note f)		33,003			25,150			37,590			14,195			25,597
Non-controlling interest		5,053			1,406			3,418			(110	)		—
Net earnings before change in accounting principle — U.S. GAAP		43,978			49,314			65,869			103,712			22,055
Cumulative effect of change in accounting principle, net (Note h)		—			—			—			(5,681	)		—
Net earnings — U.S. GAAP	$	43,978		$	49,314		$	65,869		$	98,031		$	22,055
Net earnings per common share before change in accounting principle — U.S. GAAP
Basic	$	0.35		$	0.42		$	0.56		$	0.89		$	0.19
Diluted	$	0.34		$	0.40		$	0.53		$	0.85		$	0.19
Net earnings per common share — U.S. GAAP
Basic	$	0.35		$	0.42		$	0.56		$	0.84		$	0.19
Diluted	$	0.34		$	0.40		$	0.53		$	0.80		$	0.19

Statements of Other Comprehensive Income

	Nine months ended
	September 30,				Years ended December 31,
	2005		2004		2004		2003		2002
Net earnings for the period — U.S. GAAP	$	43,978	$	49,314	$	65,869	$	98,031	$	22,055
Accounting for hedging (Note f)		—		—		—		858		(1,741	)
Comprehensive income (Note e)	$	43,978	$	49,314	$	65,869	$	98,889	$	20,314

F-30

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19. United States accounting principles and reporting(continued)

Condensed Consolidated Balance Sheets

	As at				As at December 31,
	September 30, 2005				2004				2003
	As		U.S.		As		U.S.		As			U.S.
	reported		GAAP		reported		GAAP		reported			GAAP
Assets
Cash (Note d)	$	16,900	$	16,900	$	10,068	$	10,068	$	15,548		$	11,378
Other current assets (Note d)		120,342		120,342		117,098		117,098		94,937			99,107
Property and equipment		1,447,683		1,447,683		1,178,550		1,178,550		942,303			942,303
Goodwill		7,914		7,914		7,914		7,914		—			—
Deferred financing charges and other (Note g)		8,281		5,973		9,729		6,944		11,532			8,109
Deferred risk management loss (Note f)		6,021		—		7,252		—		—			—
Unrealized loss on guarantee (Note i)		—		1,351		—		1,623		—			—
	$	1,607,141	$	1,600,163	$	1,330,611	$	1,322,197	$	1,064,320		$	1,060,897
Liabilities and shareholders’ equity
Current liabilities	$	203,259	$	203,259	$	345,784	$	345,784	$	253,142		$	253,142
Bank debt		260,000		260,000		—		—		—			—
Senior term notes (Note g)		191,582		189,274		198,594		195,809		213,246			209,823
Asset retirement obligations		22,437		22,437		18,006		18,006		17,329			17,329
Unrealized hedge loss (Note f)		12,255		12,255		11,416		11,416		—			10,895
Guarantee obligation (Note i)		—		1,351		—		1,623		—			—
Future income taxes (Notes c, f, h)		290,856		288,490		261,196		258,357		223,807			219,561
Non-controlling interest		69,711		69,711		71,537		71,537		(110	)		(110	)
		1,050,100		1,046,777		906,533		902,532		707,414			710,640
Capital stock (Note d)		226,119		256,106		135,526		165,513		131,577			161,564
Contributed surplus		7,611		7,611		3,840		3,840		760			760
Retained earnings		323,311		289,669		284,712		250,312		224,569			187,933
		557,041		553,386		424,078		419,665		356,906			350,257
	$	1,607,141	$	1,600,163	$	1,330,611	$	1,322,197	$	1,064,320		$	1,060,897

F-31

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19. United States accounting principles and reporting(continued)

Condensed Consolidated Statements of Cash Flows

	Nine months ended
	September 30,						Years ended December 31,
	2005			2004			2004			2003			2002
Operating activities
Net earnings	$	43,978		$	49,314		$	65,869		$	98,031		$	22,055
Amortization of deferred charges and other		1,447			1,596			2,101			2,208			1,367
Depletion and depreciation		74,499			58,246			82,554			61,749			54,931
Accretion of asset retirement obligations		1,416			1,261			1,670			7,117			1,072
Unrealized foreign exchange (gain) loss		(7,012	)		(4,703	)		(14,652	)		(47,388	)		1,583
Future income taxes		31,529			22,470			34,839			10,913			24,169
Unrealized risk management (gain) loss		33,699			3,351			(1,464	)		24,296			(8,659	)
Other		8,916			4,014			6,214			(2,033	)		(446	)
Change in non-cash working capital		36,522			(458	)		20,742			20,525			(16,702	)
Cash from operating activities		224,994			135,091			197,873			175,418			79,370
Cash from financing activities		122,064			83,723			111,179			121,443			75,780
Cash used in investing activities (Note j)		(340,226	)		(216,475	)		(310,362	)		(285,483	)		(155,150	)
Change in cash		6,832			2,339			(1,310	)		11,378			—
Cash, beginning of period		10,068			11,378			11,378			—			—
Cash, end of period	$	16,900		$	13,717		$	10,068		$	11,378		$	—

F-32

Compton Petroleum Corporation

Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)

(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19. United States accounting principles and reporting(continued)

Notes to the consolidated financial statements

a)	Full cost accounting
	The full cost method of accounting for crude oil and natural gas operations under Canadian and U.S. GAAP differ in the following respects. Under U.S. GAAP, an impairment test is applied to ensure the unamortized capitalized costs in each cost centre do not exceed the sum of the present value, discounted at 10%, of the estimated constant dollar, future net operating revenue from proved reserves plus unimpaired unproved property costs less applicable taxes. Under Canadian GAAP, a similar impairment test calculation is performed with the exception that cash flows from proved reserves are undiscounted and utilize forecasted pricing to determine whether impairments exist. If an impairment exists, then the amount of the write down is determined using the fair value of reserves. The Company has completed an impairment test calculation at December 31, 2004 and for all prior years, with no write-downs required under either Canadian or U.S. GAAP.
b)	Stock-based compensation
	Under Canadian GAAP, compensation costs have been recognized in the consolidated financial statements for stock options granted to employees and directors on or after January 1, 2003. For the effect on periods prior to 2003 of stock-based compensation on the Canadian GAAP financials, which would be the same adjustment under U.S. GAAP, see Note 11.
c)	Future income taxes
	Under U.S. GAAP enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted tax rates. The future income tax adjustments included in the reconciliation of net earnings under Canadian GAAP to U.S. GAAP and the balance sheet effects include the effect of such rate differences, if any, as well as the tax effect of the other reconciling items noted.
	The net future income tax liability is comprised of:

	As at
	September 30,			As at December 31,
	2005			2004			2003
Future income tax liabilities
Property and equipment	$	230,353		$	199,931		$	169,855
Timing of partnership items		76,903			67,089			62,975
Foreign exchange gain on long-term debt		11,346			10,169			7,934
Future income tax assets
Attributed Canadian royalty income		(6,857	)		(9,015	)		(9,667	)
Asset retirement obligations		(7,546	)		(6,057	)		(6,024	)
Non-capital losses carried forward		—			(53	)		(789	)
Other		(15,709	)		(3,707	)		(4,723	)
Future income taxes	$	288,490		$	258,357		$	219,561

F-33

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19.	United States accounting principles and reporting(continued)
d)	Flow through shares
	U.S. GAAP requires 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.
	There have been no flow-through shares issued subsequent to 2003. The impact of recording flow-through shares at their fair value for the year ended December 31, 2003, was to increase the future income tax provision by $0.7 million (2002 — $5.4 million) and to increase capital stock by a corresponding amount.
	During 2003, the Company received $4.2 million in proceeds from the issuance of flow-through shares of which $4.2 million remained unspent as at December 31, 2003 (2002 — $17.6 million). Accordingly, under U.S. GAAP, these proceeds would be disclosed separately on the balance sheet as restricted cash and would not be treated as cash or cash equivalents for statement of cash flow reporting purposes. At December 31, 2002, the separate disclosure of restricted cash resulted in a negative ending cash balance which was reallocated to short term debt and reflected as a financing activity in the consolidated statements of cash flow.
e)	Comprehensive income
	Statement of Financial Accounting Standards 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 comprehensive income other than as described under Note 19(f).
f)	Derivative instruments and hedging
	On January 1, 2004, the Company implemented under Canadian GAAP, EIC 128 which requires derivatives not designated as hedges to be recorded on the balance sheet as either assets or liabilities at their fair value. Changes in the derivative’s fair value are recognized in current period earnings. Under the transitional rules, any gain or loss at the implementation date is deferred and recognized into revenue once realized. At January 1, 2004, a deferred loss was recognized in the amount of $10.9 million. During the nine months ended September 30, 2005, $1.2 million (year ended December 31, 2004 — $3.6 million) of the deferred loss was charged to earnings. The remaining balance of $6.0 million (December 31, 2004 — $7.3 million) relates to the interest rate swap and will be recognized in annual amounts of $1.6 million until eliminated in 2009. Currently, the Company has not designated any of its financial instruments as hedges for accounting purposes.
	For U.S. GAAP, the Company adopted Statement of Financial Accounting Standards (“SFAS”) 133 effective January 1, 2001. SFAS 133 requires all derivatives to be recorded on the balance sheet as either assets or liabilities at their fair value. Changes in the derivative’s fair value are recognized in current period earnings unless specific hedge accounting criteria are met. To eliminate future GAAP reconciling items the Company has not designated any of its financial instruments, for the nine months ended September 30, 2005 and the year ended December 31, 2004, as hedges for U.S. GAAP purposes under SFAS 133.

F-34

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19.	United States accounting principles and reporting(continued)
	The deferred loss, recognized at January 1, 2004 under the Canadian GAAP transitional provision of EIC 128, has already been recognized in earnings for U.S. GAAP and becomes a reconciling item at September 30, 2005 and December 31, 2004.
	Prior to January 1, 2004, the natural gas and crude oil futures contracts were accounted for as cash flow hedges. These contracts were recorded at fair value on the balance sheet as a $2.0 million liability at December 31, 2003. The effective portion of the change in fair value is recorded in comprehensive income, net of tax. The ineffective portion of the change in fair value was recorded in net earnings, net of tax. The effective portion of these commodity contracts was a $0.9 million gain, which is recorded in comprehensive income as at December 31, 2003 (2002 — $1.7 million loss). The ineffective portion of these commodity contracts is $nil which is recorded in net earnings as at December 31, 2003 (2002 — $0.3 million loss).
	During 2003, it was determined that the interest rate swap arrangements relating to the Company’s senior term notes, Note 7, do not qualify for hedge accounting in accordance with SFAS 133 and should be accounted for on a mark-to-market basis. Accordingly, 2002 comparative amounts have been restated to reflect the appropriate accounting treatment. As a result, the change in the fair value of the interest rate swap arrangements of $15.4 million, previously recorded as an increase to the senior term notes, was charged to earnings, net of the future income taxes of $6.5 million, with a corresponding increase in net earnings and retained earnings of $8.9 million. Basic earnings per share and diluted earnings per share for the year ended December 31, 2002, increased $0.07 and $0.08 per share respectively, as a result of the restatement.
g)	Deferred financing charges
	Under U.S. GAAP, discounts on long-term debt are classified as a reduction of long-term debt rather than as deferred financing charges. At September 30, 2005 deferred financing charges and senior term notes were reduced by $2.3 million (December 31, 2004 — $2.8 million, 2003 - $3.4 million).
h)	Asset retirement obligations
	In 2003, the Company early adopted the Canadian Accounting Standard for asset retirement obligations, as outlined in the CICA handbook, section 3110. This standard is equivalent to U.S. SFAS 143, “Accounting for Asset Retirement Obligations”, which was effective for fiscal periods beginning on or after January 1, 2003. Early adopting the Canadian standard eliminated a U.S. GAAP reconciling item in respect to accounting for the obligations. However, a difference is created in how the transition amounts are disclosed. U.S. GAAP requires the cumulative impact of a change in an accounting principle be presented in the current year consolidated statement of earnings and prior periods not be restated. Consequently, prior year comparative periods, under U.S. GAAP, have been revised to eliminate the prior period restatement made under Canadian GAAP.

F-35

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19.	United States accounting principles and reporting(continued)
i)	Guarantee
	As discussed in Note 4 to the consolidated financial statements, MPP has guaranteed payment of certain obligations of its limited partner under a credit agreement between the limited partner and a syndicate of lenders. Canadian GAAP requires disclosure only, of this type of financial arrangement. U.S. GAAP, under FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”, requires the fair valuation of the guarantee and the inclusion of the liability in the consolidated balance sheets.
j)	Statements of cash flow
	The consolidated statements of cash flow include under investing activities, changes in working capital for items not affecting cash, such as accounts payable and accounts receivable, related to the non-cash elements of property and equipment additions. This presentation is not permitted under U.S. GAAP. The amount for the nine months ended September 30, 2005 of $39.9 million (2004 — $(1.8) million) and year ended December 31, 2004 of $29.2 million (2003 — $8.7 million, 2002 – $1.0 million) has been reallocated to the change in non-cash operating working capital for U.S. GAAP presentation purposes.
k)	Receivable and payable amounts

	As at
	September 30,		As at December 31,
	2005		2004		2003
	(in thousands of Canadian dollars)
Accounts receivable and other includes the following:
Revenue receivable	$	88,401	$	72,510	$	63,687
Joint interest receivable		23,664		32,077		21,685
Other receivables		8,277		12,511		13,735
	$	120,342	$	117,098	$	99,107

	As at
	September 30,		As at December 31,
	2005		2004		2003
	(in thousands of Canadian dollars)
Accounts payable and accrued liabilities includes the following:
Trade payables	$	138,022	$	97,608	$	67,753
Royalties payable		24,005		18,488		10,920
Other payables		10,359		9,387		7,212
	$	172,386	$	125,483	$	85,885

F-36

Compton Petroleum Corporation
Notes to the Consolidated Financial Statements

(Tabular amounts in thousands of dollars, unless otherwise stated)
(Information as at September 30, 2005 and for the nine month period ended September 30, 2005 and 2004 is unaudited)

19.	United States accounting principles and reporting(continued)
l)	Recent accounting pronouncements
	During 2004, the following new standards were issued:
	Exchange of non-monetary assets
	In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153 “Exchanges of Non-monetary Assets – an amendment of APB Opinion No. 29”. This Statement amends APB Opinion 29 to eliminate the exception for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. A non-monetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The adoption of this Standard is not expected to have any material impact on the Company’s financial position or results of operations.
	Share-based payment
	Also in December 2004, the FASB issued revised SFAS No. 123 “Share-Based Payment”. This Statement requires that the cost resulting from all share-based transactions be recorded in the financial statements. The Statement establishes fair value as the measurement objective in accounting for share-based payment arrangements and requires all entities to apply a fair-value-based measurement in accounting for share-based payment transactions with employees. The Statement also establishes fair value as the measurement objective for transactions in which an entity acquires goods or services from non-employees in share-based payment transactions. The Statement replaces FASB Statement No. 123 “Accounting for Stock-Based Compensation” and supersedes APB Opinion No. 25 “Accounting for Stock Issued to Employees”. The provisions of this Statement will be effective for the Company beginning with its fiscal year ending 2006. The Company is currently evaluating the impact this new Standard will have on its operations, but believes that it will not have a material impact on the Company’s financial position or results of operations.

F-37

]

Supplemental Oil and Natural Gas Information(unaudited)

A) Net Proved Oil and Natural Gas Reserves

The net proved oil and natural gas reserve estimates as at December 31, 2004, 2003 and 2002 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 price 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,
	2004						2003						2002
	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		14,542			326,573			10,723			314,501			9,777			262,448
Revisions of previous estimates		2,797			16,547			2,297			(12,821	)		529			11,712
Extensions, discoveries and other additions		3,026			47,713			2,869			54,128			1,829			58,853
Acquisitions of minerals in place		427			9,444			404			2,333			514			18,805
Dispositions of minerals in place		(440	)		(3,160	)		—			—			(84	)		(5,343	)
Production		(1,581	)		(37,142	)		(1,751	)		(31,568	)		(1,842	)		(31,974	)
Balance, end of year		18,771			359,975			14,542			326,573			10,723			314,501
Proved developed reserves
Balance, beginning of year		10,309			288,899			9,723			293,836			8,938			232,319
Balance, end of year		14,265			292,306			10,309			288,899			9,723			293,836

B) Capitalized Costs Related to Oil and Natural Gas Activities

The aggregate capitalized costs of oil and natural gas activities and costs incurred in oil and natural gas property acquisitions, development and exploration activities are as follows (excluding MPP and parts inventory):

Capitalized costs

	As at December 31,
	2004			2003
	(in thousands of Canadian dollars)
Proved properties	$	1,218,826		$	939,598
Unproved properties:
Acquisition		117,194			103,977
Exploration		83,238			69,820
Accumulated depletion and depreciation		(318,583	)		(238,413	)
	$	1,100,675		$	874,982

F-38

Supplemental Oil and Natural Gas Information(unaudited) (continued)

Costs incurred on unproved properties

			Includes costs incurred in
	Cumm.
As at December 31,	2004		2004		2003		2002			Prior Years
(in thousands of Canadian dollars)
Acquisition	$	117,194	$	13,217	$	2,933	$	(9,720	)	$	110,764
Exploration		83,238		13,418		15,615		4,000			50,205
	$	200,432	$	26,635	$	18,548	$	(5,720	)	$	160,969

Costs incurred

	Years ended December 31,
	2004		2003		2002
	(in thousands of Canadian dollars)
Acquisition costs (net of disposition)
Proved properties	$	12,686	$	11,224	$	27,157
Unproved properties		13,217		2,933		(9,720	)
Development costs
Development of proved undeveloped reserves		60,227		25,232		21,280
Other		136,198		115,612		52,971
Exploration costs		76,648		64,615		63,462
Total costs incurred	$	298,976	$	219,616	$	155,150

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.

C) 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. The computation also excludes values attributable to the Company’s midstream interests, referred to in the Financial Statements as MPP.

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 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 percent annual discount rate to arrive at the Standardized Measure.

F-39

Supplemental Oil and Natural Gas Information(unaudited) (continued)

	Years ended December 31,
	2004			2003			2002
	(in thousands of Canadian dollars)
Future cash inflows	$	3,160,270		$	2,467,604		$	2,460,747
Future production costs		(971,392	)		(785,187	)		(507,576	)
Future development costs		(102,557	)		(76,708	)		(56,209	)
Future net cash flows		2,086,321			1,605,709			1,896,962
Income taxes		(539,539	)		(460,291	)		(733,434	)
Total undiscounted future net cash flows		1,546,782			1,145,418			1,163,528
10 percent annual discount for estimated timing of cash inflows		(793,904	)		(592,409	)		(509,831	)
Standardized measure of discounted future net cash flows	$	752,878		$	553,009		$	653,697

⁽¹⁾ The Company estimates that it will incur $31.4 million in 2005, $24.1 million in 2006 and $5.6 million in 2007 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,
	2004			2003			2002
	(in thousands of Canadian dollars)
Beginning of year	$	553,009		$	653,697		$	317,461
Sales of production, net of production costs		(226,408	)		(197,323	)		(126,745	)
Net change in sales prices, net of production costs		42,728			(64,509	)		502,652
Extensions, discoveries and additions		161,106			144,565			198,811
Changes in estimated future development costs		(54,838	)		(39,965	)		(58,187	)
Development costs incurred during the period which reduced future development costs		184,053			85,586			66,881
Revisions in quantity estimates		306,271			(69,386	)		70,721
Accretion of discount		75,908			101,612			42,348
Purchase of reserves		(7,749	)		6,328			55,129
Sales of reserves		4,416			—			(20,051	)
Net change in income tax		(42,270	)		156,350			(234,813	)
Changes in production rates (timing) and other		(243,348	)		(223,946	)		(160,510	)
Standardized measure, end of year	$	752,878		$	553,009		$	653,697

F-40

AUDITOR’S CONSENT

Dated: December 23, 2005

Consent of GRANT THORNTON, LLP

          We have read the short form prospectus (“Prospectus”) of Compton Petroleum Finance Corporation (“Compton Finance”) dated December 23, 2005 relating to a registered offer in the United States to exchange the 7⅝% US$300,000,000 aggregate principal amount of senior notes due 2013 of Compton Finance that are validly tendered for 7⅝% US$300,000,000 aggregate principal amount of senior notes due 2013 of Compton Finance, that have been registered under the United States Securities Act of 1933, as amended. We have complied with Canadian generally accepted standards for an auditor’s involvement with offering documents.

          We consent to the use in the above-mentioned Prospectus of our report dated March 15, 2005, except for Note 18a) which is as of November 22, 2005 and Note 18b) which is as of December 23, 2005, addressed to the Board of Directors and shareholders of Compton Petroleum Corporation (“Compton”) on the consolidated balance sheets of Compton as at December 31, 2004 and 2003, and the consolidated statements of earnings, retained earnings and cash flow for each of the years in the three year period ended December 31, 2004.

(Signed) “Grant Thornton LLP”
Chartered Accountants
Calgary, Alberta
Canada
December 23, 2005

A-1

CERTIFICATES

Date: December 23, 2005

     This short form prospectus, together with the documents incorporated herein by reference, constitutes full, true and plain disclosure of all material facts relating to the securities offered by this short form prospectus as required by the securities legislation of the province of Alberta.

COMPTON PETROLEUM CORPORATION

(signed)E.G. Sapieha	(signed)N.G. Knecht
President and	Vice President, Finance and
Chief Executive Officer	Chief Financial Officer

ON BEHALF OF THE BOARD OF DIRECTORS:

(signed)Mel F. Belich	(signed)John W. Preston
Director	Director

COMPTON PETROLEUM FINANCE CORPORATION

(signed)E.G. Sapieha	(signed)N.G. Knecht
President and	Vice President, Finance and
Chief Executive Officer	Chief Financial Officer

ON BEHALF OF THE BOARD OF DIRECTORS:

(signed) Mel F. Belich	(signed)John W. Preston
Director	Director

C-1

HORNET ENERGY LTD.

(signed)E.G. Sapieha	(signed) N.G. Knecht
President and	Vice President, Finance and
Chief Executive Officer	Chief Financial Officer

ON BEHALF OF THE BOARD OF DIRECTORS:

(signed) Mel F. Belich	(signed)John W. Preston
Director	Director

COMPTON PETROLEUM HOLDINGS CORPORATION

(signed)E.G. Sapieha	(signed)N.G. Knecht
President and	Vice President, Finance and
Chief Executive Officer	Chief Financial Officer

ON BEHALF OF THE BOARD OF DIRECTORS:

(signed) Mel F. Belich	(signed)John W. Preston
Director	Director

COMPTON PETROLEUM, by its managing partner, COMPTON PETROLEUM CORPORATION

(signed)E.G. Sapieha	(signed)N.G. Knecht
President and	Vice President, Finance and
Chief Executive Officer	Chief Financial Officer

ON BEHALF OF THE BOARD OF DIRECTORS:

(signed) Mel F. Belich	(signed)John W. Preston
Director	Director

C-2

PART II

INFORMATION NOT REQUIRED TO BE DELIVERED
TO OFFEREES OR PURCHASERS

Indemnification

     In connection with each Registrant which is a corporation, the Business Corporations Act (Alberta) (“ABCA”) and the Canada Business Corporations Act (“CBCA”) 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 or she 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 or she 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 or she had reasonable grounds for believing that his conduct was lawful. A director or officer is entitled to indemnification as a matter of right if he or she was substantially successful on the merits, fulfilled the conditions set forth above, and is fairly and reasonably entitled to indemnity.

     The by-laws of each corporate Registrant provide that it shall indemnify Indemnified Persons of such Registrant to the maximum extent permitted by the ABCA or CBCA, as applicable.

     In connection with Compton Petroleum partnership, 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 it or he is a partner. The partners to the Compton Petroleum partnership are incorporated under the ABCA and CBCA, respectively; accordingly, the indemnification of the directors or officers of each partnership will be as set forth above with respect to corporate Registrants.

     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 Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable.

     The Registrants carry certain insurance coverage, in respect of potential claims against their respective directors and officers and in respect of losses of which such Registrants may be required or permitted by law to indemnify their directors and officers.

PART III

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Item 1.     Undertaking

     Each of the Registrants undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to the securities registered pursuant to Form F-10 or to transactions in said securities.

Item 2.     Consent to Service of Process

     Concurrent with the filing of the Registration Statement on Form F-10 dated December 5, 2005, the Registrants each filed with the Commission a written irrevocable consent and power of attorney on Form F-X.

     Any change to the name or address of the agent for service of process of the Registrants shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

SIGNATURES

     Pursuant to the requirements of the Securities Act of 1933, the Registrants certify that they have reasonable grounds to believe that they meet all of the requirements for filing on Form F-10 and have duly caused this Amendment No. 1 to the Registration Statement to be signed on their behalf by the undersigned, thereunto duly authorized, in the City of Calgary, in the Province of Alberta, Country of Canada, on December 23, 2005.

COMPTON PETROLEUM FINANCE
CORPORATION
 

/s/ Norm G. Knecht  

Norm G. Knecht, Vice-President, Finance 

and Chief Financial Officer 

COMPTON PETROLEUM CORPORATION
 

/s/ Norm G. Knecht  

Norm G. Knecht, Vice-President, Finance 

and Chief Financial Officer 

COMPTON PETROLEUM PARTNERSHIP,
by its managing partner,
COMPTON PETROLEUM CORPORATION
 

/s/ Norm G. Knecht  

Norm G. Knecht, Vice-President, Finance 

and Chief Financial Officer 

COMPTON PETROLEUM HOLDINGS
CORPORATION
 

/s/ Norm G. Knecht  

Norm G. Knecht, Vice-President, Finance 

and Chief Financial Officer 

HORNET ENERGY LTD
 

/s/ Norm G. Knecht  

Norm G. Knecht, Vice-President, Finance 

and Chief Financial Officer 

SIGNATURES WITH RESPECT TO COMPTON PETROLEUM FINANCE CORPORATION

     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 and on the dates indicated.

Signature	Title	Date
/s/ Ernie G. SapiehaErnie G. Sapieha	President, Chief Executive Officer, Chairman and Director	December 23, 2005
/s/ Norm G. KnechtNorm G. Knecht	Vice-President, Finance & Chief Financial Officer	December 23, 2005
/s/ Tim G. MillarTim G. Millar	Vice-President & Corporate Secretary and Director	December 23, 2005
*John W. Preston	Director	December 23, 2005
*Mel F. Belich	Director	December 23, 2005
* Pursuant to Power of Attorney
/s/ Tim G. MillarTim G. Millar, Attorney-in-fact

SIGNATURES WITH RESPECT TO COMPTON PETROLEUM CORPORATION

     Pursuant to the requirements of the Securities Act, this Amendment No. 1 to Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ernie G. SapiehaErnie G. Sapieha	President, Chief Executive Officer, Chairman and Director	December 23, 2005
/s/ Norm G. KnechtNorm G. Knecht	Vice-President, Finance & Chief Financial Officer	December 23, 2005
/s/ Tim G. MillarTim G. Millar	Vice-President, General Counsel & Corporate Secretary	December 23, 2005
*John W. Preston	Director	December 23, 2005
*Mel F. Belich	Director	December 23, 2005
*Irvin J. Koop	Director	December 23, 2005
*Jeffrey T. Smith	Director	December 23, 2005
*John A. Thomson	Director	December 23, 2005
* Pursuant to Power of Attorney
/s/ Tim G. MillarTim G. Millar, Attorney-in-fact

SIGNATURES WITH RESPECT TO COMPTON PETROLEUM PARTNERSHIP,
by its managing partner,
COMPTON PETROLEUM CORPORATION

     Pursuant to the requirements of the Securities Act, this Amendment No. 1 to Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ernie G. SapiehaErnie G. Sapieha	President, Chief Executive Officer, Chairman and Director	December 23, 2005
/s/ Norm G. KnechtNorm G. Knecht	Vice-President, Finance & Chief Financial Officer	December 23, 2005
/s/ Tim G. MillarTim G. Millar	Vice-President, General Counsel & Corporate Secretary	December 23, 2005

SIGNATURES WITH RESPECT TO COMPTON PETROLEUM HOLDINGS CORPORATION

     Pursuant to the requirements of the Securities Act, this Amendment No. 1 to Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ernie G. SapiehaErnie G. Sapieha	President, Chief Executive Officer, Chairman and Director	December 23, 2005
/s/ Norm G. KnechtNorm G. Knecht	Vice-President, Finance & Chief Financial Officer	December 23, 2005
/s/ Tim G. MillarTim G. Millar	Vice-President & Corporate Secretary and Director	December 23, 2005
*John W. Preston	Director	December 23, 2005
*Mel F. Belich	Director	December 23, 2005
* Pursuant to Power of Attorney
/s/ Tim G. MillarTim G. Millar, Attorney-in-fact

SIGNATURES WITH RESPECT TO HORNET ENERGY LTD

     Pursuant to the requirements of the Securities Act, this Amendment No. 1 to Registration Statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ernie G. SapiehaErnie G. Sapieha	President, Chief Executive Officer, Chairman and Director	December 23, 2005
/s/ Norm G. KnechtNorm G. Knecht	Vice-President, Finance & Chief Financial Officer	December 23, 2005
/s/ Tim G. MillarTim G. Millar	Vice-President & Corporate Secretary and Director	December 23, 2005
*John W. Preston	Director	December 23, 2005
*Mel F. Belich	Director	December 23, 2005
* Pursuant to Power of Attorney
/s/ Tim G. MillarTim G. Millar, Attorney-in-fact

AUTHORIZED REPRESENTATIVE

     Pursuant to the requirements of Section 6(a) of the Securities Act of 1933, Compton Petroleum (U.S.A.) Corporation, as the Authorized Representative, has duly caused this Amendment No. 1 to Registration Statement to be signed on its behalf by the undersigned, solely in its capacity as the duly authorized representative of Compton Petroleum Finance Corporation, Compton Petroleum Corporation, Compton Petroleum, Compton Petroleum Holdings Corporation and Hornet Energy Ltd. in the United States, on December 23, 2005.

COMPTON PETROLEUM (U.S.A.) CORPORATION
 

/s/ Norm G. Knecht  

Norm G. Knecht, Authorized Signatory 

EXHIBITS

Exhibit
Number		Description
	3.1*	Purchase Agreement dated November 15, 2005 by and among Compton Petroleum Finance Corporation, the Guarantors identified therein and the Initial Purchasers identified therein
	3.2*	Registration Rights Agreement dated November 22, 1005 by and among Compton Petroleum Finance Corporation, the Guarantors identified therein and the Initial Purchasers identified therein
	4.1*	Renewal Annual Information Form of Compton Petroleum Corporation dated March 23, 2005 (incorporated herein by reference to Compton Petroleum Corporation’s Annual Report on Form 40-F, filed with the Commission on April 1, 2005)
	4.2*	Management proxy circular of Compton Petroleum Corporation dated March 4, 2005, relating to the annual general and special meeting of the holders of common shares of Compton Petroleum Corporation held on May 10, 2005 (excluding those portions which appear under the headings “Performance Graph”, “Report on Executive Compensation” and “Statement of Corporate Governance Practices”) (incorporated by reference to Compton Petroleum Corporation’s Annual Report on Form 40-F, filed with the Commission on April 1, 2005 and incorporated herein by reference)
	4.3*	Audited consolidated balance sheets of Compton Petroleum Corporation as at December 31, 2004 and 2003, and the audited consolidated statements of earnings, retained earnings and cash flow for each of the years in the three year period ended December 31, 2004, together with the notes thereto and the auditors’ report thereon (incorporated by reference to Compton Petroleum Corporation’s Annual Report on Form 40-F, filed with the Commission on April 1, 2005 and incorporated herein by reference)
	4.4*	Management’s Discussion and Analysis for the years ended December 31, 2004 and 2003 (incorporated by reference to Compton Petroleum Corporation’s Annual Report on Form 40-F, filed with the Commission on April 1, 2005 and incorporated herein by reference)
	4.5*	Unaudited interim consolidated financial statements of Compton Petroleum Corporation for the nine months ended September 30, 2005 and 2004 (incorporated by reference to Compton Petroleum Corporation’s Form 6-K, filed with the Commission on November 28, 2005 and incorporated herein by reference)
	4.6*	Management’s Discussion ad Analysis for the nine months ended September 30, 2005 and 2004 (incorporated by reference to Compton Petroleum Corporation’s Form 6-K, filed with the Commission on November 28, 2005 and incorporated herein by reference)
	5.1*	Consent of Outtrim Szabo Associates Ltd. (now DeGolyer and MacNaughton Canada Limited)
	5.2*	Consent of Netherland, Sewell & Associates, Inc.
	5.3	Consent of Grant Thornton LLP
	6.1*	Powers of Attorney (Reference is made to the signature page included with the initial filing of the Registration Statement on Form F-10 dated as of December 5, 2005)
	7.1*	Indenture dated as of November 22, 2005 by and among Compton Petroleum Finance Corporation, Compton Petroleum Corporation, the Subsidiary Guarantors identified therein and The Bank of Nova Scotia Trust Company of New York
	7.2	Statement of Eligibility of the Trustee on Form T-1
	99.1*	Form of Letter of Transmittal
	99.2*	Form of Notice of Guaranteed Delivery

* Previously filed.