Luke Energy 20-F/A 2004 FY Annual report (foreign) (amended)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)
o	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
OR
x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the period endedDecember 31, 2004
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________________ to ______________________

Commission file number _________________________

LUKE ENERGY LTD.
(Exact name of Registrant as specified in its charter)
LUKE ENERGY LTD.
(Translation of Registrant's name into English)
Canada
(Jurisdiction of incorporation or organization)
Suite 1200, 520 - 5th Avenue S.W., Calgary, Alberta, CANADA, T2P 3R7
Address of principal executive offices
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of each class	Name of each exchange on which registered
N/A	N/A
Securities registered or to be registered pursuant to Section 12(g) of the Act.
Common Shares
(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.

N/A

(Title of Class)

Indicate the number of outstanding shares of each of the issuer's class of capital or common stock as at December 31, 2004.

36,997,823 Common Shares

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x Yes o No

Indicate by check mark which financial statement item the registrant has elected to follow.

x Item 17 o Item 18

2

TABLE OF CONTENTS

PART I		7
ITEM 1	IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS	7
ITEM 2	OFFER STATISTICS AND EXPECTED TIMETABLE	7
ITEM 3	KEY INFORMATION	7
	A.Selected Financial Data	7
	B.Capitalization and Indebtedness	10
	C.Reasons for the Offer and Use of Proceeds	10
	D.Risk Factors	10
ITEM 4	INFORMATION ON THE COMPANY	17
	A.History and Development of the Company	17
	B.Business Overview	18
	C.Organizational Structure	22
	D.Property, Plant and Equipment	23
ITEM 5	OPERATING AND FINANCIAL REVIEW PROSPECTS	26
	A.Operating Results	28
	B.Liquidity and Capital Resources	31
	C.Research and Development	31
	D.Trend Information	32
	E.Off-balance Sheet Arrangements	33
	F.Disclosure of Contractual Obligations	33
	G.Safe Harbor	33
ITEM 6	DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES	33
	A.Directors and Senior Management	33
	B.Compensation	36
	C.Board Practices	36
	D.Employees	42
	E.Share Ownership	42
ITEM 7	MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS	44
	A.Major Shareholders	44
	B.Related Party Transactions	44
ITEM 8	FINANCIAL INFORMATION	45
	A.Financial Information	45
	B.Significant Changes	45
ITEM 9	THE OFFER AND LISTING	45
ITEM 10	ADDITIONAL INFORMATION	46
	A.Share Capital	46
	BMemorandum and Articles of Association	46
	C.Material Contracts	52
	D.Exchange Controls	52
	E.Taxation	52
	F.Dividends and Paying Agents	57
	G.Statement by Experts	57
	H.Documents on Display	57
	I.Subsidiary Information	57
ITEM 11	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57

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ITEM 12	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES	57
PART II		57
ITEM 13	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES	57
ITEM 14	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS	57
ITEM 15	CONTROLS AND PROCEDURES	58
ITEM 16	OTHER	58
	A.Audit Committee Financial Expert	58
	B.Code of Ethics	58
	C.Principal Accountant Fees and Services	60
	D.Exemptions from the Listing Standards for Audit Committees	60
	E.Purchases of Equity Securities by the Issuer and Affiliated Purchasers	60
ITEM 17	FINANCIAL STATEMENTS	60
ITEM 18	FINANCIAL STATEMENTS	61
ITEM 19	EXHIBITS	61

4

GLOSSARY OF TERMS

The following abbreviations and terms have the following meanings:

Crude oil and natural gas liquids:
	bbls	barrels
	mbbls	1,000 barrels
	mmbbls	million barrels
	bbls/d	barrels per day
	bopd	barrels of oil per day
Natural gas:
	mcf	1,000 cubic feet
	mmcf	1,000,000 cubic feet
	bcf	1,000,000,000 cubic feet
	mcf/d	1,000 cubic feet per day
	mmcf/d	1,000,000 cubic feet per day
	mmbtu	1,000,000 British thermal units
boe	barrel of oil equivalent at the rate of 6 mcf of gas = 1 BOE
boepd	barrels of oil equivalent per day
ngls	natural gas liquids
P&NG	petroleum and natural gas

5

Forward-Looking Statements

This annual report and the documents incorporated by reference herein contain forward-looking statements. These statements relate to future events or the Company's future performance. All statements other than statements of historical fact are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as "may", "will", "should", "expect", "plan", "anticipate", "believe", "estimate", "predict", "potential", "continue", or the negative of these terms or other comparable terminology. These statements are only predictions. Actual events or results may differ materially. In addition, this annual report and the documents incorporated by reference herein 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. Forward-looking statements in this annual report include, but are not limited to, statements with respect to:

• capital expenditure programs;

• commodity prices;

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

• the use of development activity and acquisitions to replace and add to reserves;

• drilling plans;

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

• the impact of Canadian federal and provincial governmental regulation on the Company relative to other oil and gas issuers of similar size;

• the emergence of accretive growth opportunities;

• realization of the anticipated benefits of acquisitions and dispositions; and

• the Company's ability to benefit from the combination of growth opportunities and the ability to grow through the capital markets.

Although the Company believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. The Company cannot guarantee future results, levels of activity, performance, or achievements. Moreover, neither the Company nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Some of the risks and other factors, some of which are beyond the Company's control, which could cause results to differ materially from those expressed in the forward-looking statements contained in this annual report and the documents incorporated by reference herein include, but are not limited to:

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

• industry conditions, including fluctuations in the price of oil and natural gas;

• governmental regulation of the oil and gas industry, including environmental regulation;

• fluctuation in foreign exchange or interest rates;

• unanticipated operating events which can reduce production or cause production to be shut-in or delayed;

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

• stock market volatility and market valuations;

• the need to obtain required approvals from regulatory authorities; and

• the other factors considered in Item 3D under the caption "Risk Factors".

6

Statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements contained in this annual report and the documents incorporated by reference herein are expressly qualified by this cautionary statement. The Company is not under any duty to update any of the forward-looking statements after the date of this annual report to conform such statements to actual results or to changes in the Company's expectations.

PART I

ITEM1 IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

Not Applicable.

ITEM 2 OFFER STATISTICS AND EXPECTED TIMETABLE

Not Applicable.

ITEM 3 KEY INFORMATION

A. Selected Financial Data

The financial statements of Luke Energy Ltd. ("Luke", the "Company", "us", "we", or "our") have been prepared in accordance with generally accepted accounting principles in Canada. Except as described in Note 13 to the Company's audited comparative financial statements for the year ended December 31, 2004 and the period ended December 31, 2003, there are no material differences for the purposes of such financial statements between generally accepted accounting principles in Canada and the United States.

The following tables set forth selected financial information for the periods and the dates indicated. It should be read in conjunction with Item 5 -"Operating and Financial Review and Prospects" and the Company's audited comparative financial statements for the year ended December 31, 2004 and the period ended December 31, 2003 included herein.

(Amounts stated in Canadian dollars)

Canadian GAAP	Year Ended Dec. 31, 2004	Period ended Dec. 31, 2003(1)
	($)	($)
Revenue net of royalties	8,696,928	1,280,933
Earnings before taxes	2,170,442	756,634
Net earnings for the period	1,100,442	369,834
Earnings per Common Share - basic and diluted	0.03	0.01
Total assets	59,447,703	45,227,643
Net assets	50,500,841	42,814,715
Capital stock	48,130,532	42,223,171
Number of shares	36,997,823	34,828,949
Dividends	NIL	NIL
Long term debt	NIL	NIL

Note:

(1) Earnings and earnings per share were restated for the period ended December 31, 2003 as a result of the Company changing the accounting policy for Stock-based compensation to the fair value method effective January 1, 2004. The effect of retroactively adopting the fair value method was to decrease earnings by $214,092 for the period ended December 31, 2003 and to increase contributed surplus by the same amount. There were no other restatements of basic and diluted numbers.

7

The Company's 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 (“US GAAP”). The significant differences in those principles, as they apply to the Company’s financial statements, are described below.

a) Full Cost Accounting

The Company is subject to a SEC prescribed ceiling test. In determining the limitation on capitalized costs, SEC rules require a 10 percent discounting of after-tax future net revenues from production of proved oil and gas reserves. The future revenues are estimated using year-end prices. To date, application of the SEC prescribed test has not resulted in a write-down of capitalized costs.

b) Flow-through Shares

The Company finances a portion of its activities with flow-through share issues whereby the tax deductions on expenditures are renounced to the share subscribers. Under Canadian GAAP the estimated cost of the tax deductions renounced to shareholders is reflected as a reduction of the stated value of the shares. The SEC requires that when the qualifying expenditures are renounced to the shareholders, the estimated tax cost of the renunciation, less any proceeds received in excess of the quoted value of the shares, is reflected as a tax expense.

c) Stock-based Compensation

Prior to 2004 the Company used the intrinsic method of accounting for stock options for both Canadian and US GAAP purposes. On January 1, 2004 the Company retroactively changed its method of accounting for stock options to the fair value method. While US GAAP continues to allow the use of either the intrinsic method, as prescribed by APB 25, or the fair value method, as prescribed by SFAS 123, the Company has elected to adopt the fair value method of accounting for stock options for US GAAP purposes. The new method has been applied retroactively with a restatement of prior period US GAAP amounts. This change resulted in a reduction in the US GAAP earnings of $698,113 ($0.02 per share) for the year ended December 31, 2004 and $214,092 ($0.01 per share) for the period ended December 31, 2003.

The following tables provide a reconciliation of earnings (loss) and the balance sheet impact for the differences between Canadian GAAP and US GAAP:

	Note		Year Ended December 31, 2004		Period Ended December 31, 2003
Earnings, as reported		$	1,100,442	$	369,834
Accounting for income taxes	(b)		-	$	(1,329,000	)
Earnings (loss) - US GAAP		$	1,100,442	$	(959,166	)
Earnings (loss) per share - US GAAP		$	0.03	$	(0.03	)

8

As at December 31, 2004	Note		As Reported		Increase (Decrease)			US GAAP
Shareholder’s equity
Share capital	(b)	$	48,130,532	$	1,329,000		$	49,459,532
Retained earnings	(b)	$	1,470,276	$	(1,329,000	)	$	141,276

As at December 31, 2003	Note		As Reported		Increase (Decrease)			US GAAP
Shareholder’s equity
Share capital	(b)	$	42,223,171	$	1,329,000		$	43,552,171
Retained earnings	(b)	$	369,834	$	(1,329,000	)	$	(959,166	)

The Company has not declared or paid any dividends during the period indicated.

Currency and Exchange Rates

All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated.

1.On April 29, 2005, the noon buying rate in New York City for cable transfer in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.7957 U.S. = $1.00 Canadian.

All exchange rate calculations in #2 and #3 below are 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.

2.The following table sets forth the high, low, average and end of period exchange rates for each month during the previous six months.

	2004			2005
	November	December	January	February	March	April
High	0.8493	0.8435	0.8460	0.8134	0.8315	0.8233
Low	0.8155	0.8064	0.8050	0.7961	0.8024	0.7957
Average	0.8357	0.8204	0.8165	0.8064	0.8224	0.8092
End of Period	0.8177	0.8310	0.8067	0.8133	0.8048	0.7957

3.The average exchange rate for the fiscal year ending December 31, 2004, calculated by using the average of the exchange rates in effect on the last day of each month during the period indicated, was $0.7682 U.S. (2003 - $0.7186 U.S.) = $1.00 Canadian. During the fiscal year ending December 31, 2004, the exchange rate high was $0.8493 U.S. (2003 - $0.7738 U.S.) = $1.00 Canadian, the exchange rate low was $0.7158 U.S. (2003 - $0.6349 U.S.) = $1.00 Canadian and the exchange rate at the end of period was $0.8310 U.S. (2003 - $0.7738 U.S.) = $1.00 Canadian.

9

B. Capitalization and Indebtedness

Not Applicable.

C. Reasons for the Offer and Use of Proceeds

Not Applicable.

D. Risk Factors

Exploration, Development and Production Risks

Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our long-term commercial success depends on our ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves we may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in our reserves will depend not only on our ability to explore and develop any properties we may have from time to time, but also on our ability to select and acquire suitable producing properties or prospects. We may not be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, we may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. Further commercial quantities of oil and natural gas may not be discovered or acquired by us.

Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions.

While diligent well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees.

Oil and natural gas exploration, development and production operations are subject to all the risks and hazards typically associated with such operations, including hazards such as fire, explosion, blowouts, cratering, sour gas releases and spills, each of which could result in substantial damage to oil and natural gas wells, production facilities, other property and the environment or in personal injury. In accordance with industry practice, we are not fully insured against all of these risks, nor are all such risks insurable. Although we maintain liability insurance in an amount that we consider consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event we could incur significant costs that could have a material adverse effect upon our financial condition. Oil and natural gas production operations are also subject to all the risks typically associated with such operations, including encountering unexpected formations or pressures, premature decline of reservoirs and the invasion of water into producing formations. Losses resulting from the occurrence of any of these risks could have a material adverse effect on future results of operations, liquidity and financial condition.

10

ReserveEstimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids reserves and cash flows to be derived therefrom, including many factors beyond the Company’s control. The reserve and associated cash flow information set forth herein represents estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. The Company’s actual production, revenues, taxes and development and operating expenditures with respect to our reserves will vary from estimates thereof and such variations could be material. Further, the evaluations are based in part on the assumed success of exploitation activities intended to be undertaken in future years. The reserves and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploitation activities do not achieve the level of success assumed in the evaluation.

Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material.

In accordance with applicable securities laws, Gilbert Laustsen Jung Associates Ltd. ("GLJ"), the independent reserves evaluator, has used both constant and forecast price and cost estimates in calculating reserve quantities included herein. Actual future net revenue will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs.

Actual production and revenues derived therefrom will vary from the estimates contained in the December 31, 2004 reserve evaluation completed by GLJ (the "GLJ Report"), and such variations could be material. The GLJ Report is based in part on the assumed success of activities the Company intends to undertake in future years. The reserves and estimated cash flows to be derived therefrom contained in the GLJ Report will be reduced to the extent that such activities do not achieve the level of success assumed in the GLJ Report. The GLJ Report is effective as of a specific effective date and has not been updated and thus does not reflect changes in the Company’s resources since that date.

11

Differences in United States and Canadian Practices for Reporting Reserves and Production

We report our production and reserve quantities in accordance with Canadian practices. These practices are different than the practices used to report production and reserve estimates in reports and other materials filed with the SEC by United States companies. The primary differences are summarized below:

• we follow the Canadian practice of reporting gross production and reserve volumes, which are prior to the deduction of royalties and similar payments. In the United States, net production and reserve volumes are reported after deduction of these amounts.

• we follow the Canadian practice of using escalating prices and costs when we estimate the quantities of our reserves. In the United States, reserve estimates are calculated using prices and costs held constant at amounts in effect at the date of the reserve report.

• we incorporate in this Form 20F filings made with Canadian securities authorities that include estimates of probable reserves. The SEC generally prohibits the inclusion of estimates of probable reserves in filings made with the SEC.

As a consequence, our production volumes and reserve estimates may not be comparable to those made by United States companies subject to SEC reporting and disclosure requirements.

Prices, Markets and Marketing

The marketability and price of oil and natural gas that may be acquired or discovered by the Company will be affected by numerous factors beyond our control. The Company’s ability to market its natural gas may depend upon our ability to acquire space on pipelines that deliver natural gas to commercial markets. The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities, and related to operational problems with such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and natural gas and many other aspects of the oil and natural gas business.

The Company’s revenues, profitability and future growth and the carrying value of its oil and gas properties are substantially dependent on prevailing prices of oil and gas. The Company’s ability to borrow and to obtain additional capital on attractive terms is also substantially dependent upon oil and gas prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include economic conditions, in the United States and Canada, the actions of the Organization of Petroleum Exporting Countries, governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports and the availability of alternative fuel sources. Any substantial and extended decline in the price of oil and gas would have an adverse effect on the Company’s carrying value of its proved reserves, borrowing capacity, revenues, profitability and cash flows from operations.

The exchange rate between the Canadian and U.S. dollar also affects the profitability of the Company and the Canadian dollar has strengthened recently against the U.S. dollar.

The Company’s current production volumes are 98% natural gas, therefore volatility in oil prices and the exchange rate between the Canadian and U.S. dollar currently have a minimal impact on the Company’s profitability. However, a $0.25 change in the natural gas price would impact cash flow by approximately $830,000 ($0.02 per share) and earnings by $475,000 ($0.01 per share).

Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. In addition, bank borrowings available to the Company are in part determined by the Company’s borrowing base. A sustained material decline in prices from historical average prices could reduce the Company’s borrowing base, therefore reducing the bank credit available to the Company which could require that a portion, or all, of the Company’s bank debt be repaid.

12

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment to the Company and may delay exploration and development activities.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

We make acquisitions and dispositions of businesses and assets in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner as well as our ability to realize the anticipated growth opportunities and synergies from combining our acquired businesses and operations. The integration of an acquired business may require substantial management effort, time and resources and may divert management’s focus from other strategic opportunities and operational matters.

Management continually assesses the value and contribution of services provided and assets required to provide such services. In this regard, as we grow, non-core assets may be disposed of, so that we can focus our efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets, if disposed of, could be expected to realize less than their carrying value on our financial statements.

Competition

Oil and gas exploration is intensely competitive in all its phases and involves a high degree of risk. We compete with numerous other participants in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. Our competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than us. Our ability to increase reserves in the future will depend not only on our ability to explore and develop our present properties, but also on our ability to select and acquire suitable producing properties or prospects for exploratory drilling. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. Competition may also be presented by alternate fuel sources.

Substantial Capital Requirements

The Company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. If the Company’s revenues or reserves decline, it may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing or cash generated by operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company’s financial condition, results of operations or prospects.

13

Additional Funding Requirements

The Company’s cash flow from its reserves may not be sufficient to fund our ongoing activities at all times. From time to time, the Company may require additional financing in order to carry out our oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause us to forfeit our interest in certain properties, miss certain acquisition opportunities and reduce or terminate our operations. If the Company’s revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our production. If the Company’s cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available on terms acceptable to the Company.

From time to time the Company may enter into transactions to acquire assets or the shares of other companies. These transactions may be financed partially or wholly with debt, which may increase the Company’s debt levels above industry standards. Depending on future exploration and development plans, the Company may require additional equity and/or debt financing that may not be available or, if available, may not be available on favourable terms. Neither the Company’s articles nor its by-laws limit the amount of indebtedness that the Company may incur. The level of the Company’s indebtedness from time to time, could impair the Company’s ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise.

Regulatory

Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government that may be amended from time to time. See “Industry Conditions.” Our operations may require licenses from various governmental authorities. There can be no assurance that we will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at our projects and the obtaining of such licences and permits may delay our operations.

Kyoto Protocol

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 exploration and production facilities and other operations and activities emit a small amount of greenhouse gases which may subject us to legislation regulating emissions of greenhouse gases. The Government of Canada has put forward a Climate Change Plan for Canada which suggests further legislation will set greenhouse gases emission reduction requirements for various industrial activities, including oil and gas exploration and production. Future federal legislation, together with provincial emission reduction requirements, such as those in theClimate Change and Emissions Management Act (Alberta) (yet to be proclaimed), may require the reduction of emissions or emissions intensity produced by our operations and facilities. The direct or indirect costs of these regulations may adversely affect our business.

Environmental

All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations.

14

The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. Although we believe that we are in material compliance with current applicable environmental regulations, non-compliance with environmental laws may result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect our financial condition, results of operations or prospects. See “Industry Conditions”.

Title to Assets

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. It is the practice of the Company in acquiring significant oil and gas leases or interest in oil and gas leases to fully examine the title to the interest under the lease. In the case of minor acquisitions, the Company may rely upon the judgment of oil and gas lease brokers or landmen who perform the field work in examining records in the appropriate governmental office before attempting to place under lease a specific interest. The Company believes that this practice is widely followed in the oil and gas industry. Nevertheless, there may be title defects which affect lands comprising a portion of the Company’s properties. To the extent title defects do exist, it is possible that the Company may lose all or a portion of its right, title, estate and interest in and to the properties to which the title relates.

Insurance

The Company’s involvement in the exploration for and development of oil and natural gas properties may result in the Company becoming subject to liability for pollution, blowouts, property damage, personal injury or other hazards. Although the Company will generally obtain insurance prior to drilling in accordance with industry standards to address certain of these risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not in all circumstances be insurable or, in certain circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or other reasons. The payment of such uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Company’s financial position, results of operations or prospects.

Aboriginal Claims

Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada. The Company is not aware that any claims have been made in respect of its property and assets; however, if a claim arose and was successful this could have an adverse effect on the Company and its operations.

Seasonality

The level of activity in the Canadian oil and gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby reducing activity levels. Also, certain oil and gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and corresponding declines in the demand for the goods and services of the Company.

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Accounting Write-Downs as a Result of GAAP

Canadian generally accepted accounting principles (“GAAP”) requires that management apply certain accounting policies and make certain estimates and assumptions which affect reported amounts in the financial statements of the Company. The accounting policies may result in non-cash charges to net income and write-down of net assets in the financial statements. Such non-cash charges and write-downs may be viewed unfavourably by the market and result in an inability to borrow funds and/or may result in a decline in the trading price of the Company’s shares.

Under GAAP, the net amounts at which petroleum and natural gas costs on a property or project basis are carried are subject to a test which is based in part upon estimated future net cash flow from reserves. The carrying value is assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of major development projects exceeds the carrying value. When the carrying value is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying value of assets exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects. A decline in the net value of oil and natural gas properties could cause capitalized costs to exceed the cost ceiling, resulting in a charge against earnings.

Third Party Credit Risk

The Company is or may be exposed to third party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures could have a material adverse effect on the Company and its cash flow from operations.

Conflicts of Interest

The directors or officers of the Company may also be directors or officers of other oil and gas companies or otherwise involved in natural resource exploration and development and situations may arise where they are in a conflict of interest with the Company. Conflicts of interest, if any, which arise will be subject to and governed by procedures prescribed by the CBCA which require a director or officer of a company who is a party to, or is a director or an officer of, or has some material interest in any person who is a party to, a material contract or proposed material contract with the Company disclose his or her interest and, in the case of directors, to refrain from voting on any matter in respect of such contract unless otherwise permitted under the CBCA.

Reliance on Key Personnel

The Company’s success depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse affect on the Company. The contributions of these individuals to the immediate operations of the Company are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that the Company will be able to continue to attract and retain all personnel necessary for the development and operation of its business. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of the management of the Company.

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ITEM 4 INFORMATION ON THE COMPANY

A. History and Development of the Company

Luke was incorporated by Certificate of Incorporation issued pursuant to the provisions of theCanada Business Corporations Act (the “CBCA”) on January 9, 2003 as a wholly-owned subsidiary of KeyWest Energy Corporation (“KeyWest”). Pursuant to a plan of arrangement involving Viking Energy Royalty Trust, Viking Energy Holdings Inc., Viking KeyWest Inc., KeyWest and Luke, KeyWest transferred interests in certain petroleum and natural gas properties and related facilities ("the "Retained Assets") to Luke in exchange for common shares ("Common Shares") in Luke. On February 26, 2003, the closing of the plan of arrangement, the common shares of Luke held by KeyWest were distributed to shareholders of KeyWest on a one-for-ten basis. Luke began trading on the Toronto Stock Exchange on February 28, 2003.

Our common shares trade on the TSX under the symbol “LKE”.

Our head office is located at Suite 1200, 520 - 5th Avenue S.W., Calgary, Alberta, Canada, T2P 3R7 and our registered office is located at Suite 1400, 350 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 3N9. The telephone number is 403-261-4811.

Our business is the acquisition, exploration, development, production and marketing of oil and natural gas in Western Canada. Our business plan is to grow through a combination of internally generated low to medium risk drilling opportunities and strategic acquisitions with exploitation potential.

History

The initial petroleum and natural gas assets of the Company, including an interest in certain plants, facilities and installations, were transferred from KeyWest as part of the aforementioned plan of arrangement. The transferred assets included average daily production of 150 boe/d and a 100% interest in 11,720 acres of undeveloped land. We did not make any other significant property or corporate acquisitions or dispositions during 2003.

Three successful financings were completed during 2003, which collectively netted us $38.5 million. The initial financing raised $1.3 million in start-up capital through the sale to Company insiders of 1.6 million shares at 81 cents per share. A subsequent major financing in March 2003 raised net proceeds of $33.8 million pursuant to which a total of 24.8 million shares were sold at $1.45 per share with Company insiders subscribing for 10% of the issue. Finally, a September financing raised net proceeds of $3.4 pursuant to which 1.8 million shares which were issued at $2.00 per share on a tax “flow-through” basis with Company insiders subscribing for 50% of the issue.

In 2004, our operations grew as a result of a successful drilling program. We incurred capital expenditures of $28.8 million for the year and drilled 15 wells resulting in 11 successful gas wells. Nine of these successful wells were at Marten Creek in northern Alberta, establishing Marten Creek as our first core area. The other two successful wells were at Bernadet in north-eastern British Columbia.

In addition, we completed two minor property acquisitions during 2004; one at Bashaw where we bought out our 50% partner in two wells and the second was in the south-eastern part of Marten Creek where a small interest was acquired in several wells plus an interest in a pipeline and compressor, which will be used to expand our program.

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During 2004 we issued a total of 2.1 million common shares on a tax “flow-through” basis for gross proceeds of $5.7 million. Management and directors subscribed for approximately 20% of such “flow-through” common shares.

Historical Principal Capital Expenditures/Divestitures

The following table summarizes the capital expenditures incurred by us for the year ended December 31, 2004 and the period ended December 31, 2003.

Capital Expenditures ($000's)		2004		2003
Land	$	7,408	$	2,077
Seismic	$	3,192	$	1,064
Drilling and equipping	$	8,478	$	953
Facilities and flowlines	$	4,608	$	565
Pipe and casing inventory	$	2,210		-
Property acquisition	$	2,707		-
Corporate	$	215	$	176
	$	28,818	$	4,835

The increase in capital expenditures to $28.8 million this year from $4.8 million last year reflects increased activity levels. The Company drilled 15 gross (13.5 net) wells in 2004 as compared to one well in 2003. Land and seismic costs were higher than 2003 due to the expansion of the Marten Creek area as well as generating new prospect areas. In addition, the Company completed two minor property acquisitions during the year; one at Bashaw where the Company bought out its 50% partner in two wells and the second was in the southeastern part of the Marten Creek where a small interest was acquired in several wells plus an interest in a pipeline and compressor which will be used to expand the Company's program.

The Company also incurred $2.2 million of costs in December for purchasing pipe and casing for the 2005 Marten Creek drilling program. It was necessary to secure these materials in advance as supply shortages were expected given the record drilling activity.

Current and Planned Capital Expenditures/Divestitures

The total capital budget for 2005 is estimated at $46 million (approximately 60% exploration activity). $29 million of this budget is allocated to the first quarter of 2005 primarily for the Marten Creek drilling program in northern Alberta and related infrastructure. The remainder of the budget is focused on exploring for new prospects. The 2005 capital expenditure program will be funded by working capital, cash flow and credit facility borrowings. As at April 30, 2005, first quarter capital expenditures were approximately $24.5 million and were related primarily to the winter drilling program at Marten Creek in which 25 wells were drilled and 18 were cased. These expenditures include gathering systems and facilities to bring the 18 gas wells on stream.

B. Business Overview

Summary

The Company is an emerging oil and gas company based in Calgary, Alberta, Canada and operating in western Canada. The Company’s business plan is to grow through a combination of internally generated low to medium risk drilling opportunities and strategic acquisitions with exploitation potential.

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During the year ended December 31, 2004 oil and gas sales were $10,705,520 (2003 - $1,715,620). Oil and gas sales relating to the Retained Assets transferred February 26, 2003 for each of the years ended December 31 were as follows: 2002 - - $1,191,000; 2001 - $1,191,000; and 2000 - $1,786,000.

Seasonality

The Company expects its exploration and development program to be seasonably impacted. The Company, like many Western Canadian oil and gas explorers, expects to experience reduced activity in the spring as limitations on the transportation of heavy equipment on municipal roads curtails the ability of drilling rigs and other oilfield equipment to get to and from well sites. In addition, some of the Company's operations are in areas that are accessible only during the winter months.

Marketing

Luke received an average of $47.77 Cdn per barrel for its oil in 2004. Luke's production averaged 76 barrels per day of light gravity oil from Bassano (30 degrees API) and Bashaw (37 degrees API). The Company markets its crude oil under 30 day evergreen contracts with Nexen Marketing.

The Company's natural gas price averaged $6.25 Cdn per Mcf in 2004. The Company's average annual natural gas production was 4.1 MMcf per day in 2004. Luke sold more than 95% of its natural gas production to Nexen Marketing on the daily spot market during the year.

Government Regulation

The oil and gas industry is subject to extensive controls and regulations imposed by various levels of government. Outlined below are some of the more significant aspects of the legislation, regulations and agreements governing the oil and gas industry. Although it is not expected that these controls and regulations will affect our operations in a manner materially different than it would affect other oil and gas companies of a similar size, the controls and regulations should be considered carefully by investors. All current legislation is a matter of public record and we are unable to predict what additional legislation or amendments may be enacted.

Pricing and Marketing - Oil

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, the value of refined products and the supply/demand balance. Oil exports may be made pursuant to export contracts with terms not exceeding one year in the case of oil other than heavy crude, and not exceeding two years in the case of heavy crude, provided that an order approving any such export has been obtained from the National Energy Board (“NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export license from the NEB and the issue of such a license requires the approval of the Governor in Council.

Pricing and Marketing - Natural Gas

In Canada, the price of natural gas sold is determined by negotiation between buyers and sellers. Natural gas exported from Canada is subject to regulation by the NEB and the government of Canada.

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Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain criteria prescribed by the NEB and the government of Canada. Natural gas exports for a term of two years or less or for a term of between 2 and 20 years (in quantities of not more than 30,000 m3 /d) may be made pursuant to an NEB order, or, in the case of exports for a longer duration (to a maximum of 25 years) or a larger quantity, pursuant to an NEB export license and Governor in Council approval.

The governments of Alberta and British Columbia also regulate the removal of natural gas from those provinces for consumption elsewhere based on such factors as reserve availability, transportation arrangements and market considerations.

Pipeline Capacity

Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limits the ability to produce and to market natural gas production. The pro-rating of capacity on the inter-provincial pipeline systems also continues to affect the ability to export oil.

The North American Free Trade Agreement

On January 1, 1994, the North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the U.S. and Mexico became effective. The NAFTA carries forward most of the material energy terms contained in the Canada-U.S. Free Trade Agreement. In the context of energy resources, Canada continues to remain free to determine whether exports to the U.S. or Mexico will be allowed, provided that any export restrictions are justified under certain provisions of the General Agreement on Tariffs and Trade, and further provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to the total supply of the energy resource (based upon the proportion prevailing in the most recent 36 month period or in such other representative period as the parties may agree), (ii) impose an export price higher than the domestic price subject to an exception with respect to certain measures which only restrict the volume of exports, and (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export-price requirements, prohibition in any circumstances in which any other form of quantitative restriction is prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

The NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector and prohibits discriminatory border restrictions and export taxes. The agreement also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements, which is important for Canadian natural gas exports.

Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil, natural gas and natural gas liquids production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral owner and the lessee, although production from such lands is also subject to certain provincial taxes and royalties. Our operations which are not Crown lands and are subject to the provisions of specific agreements are also usually subject to royalties negotiated between the mineral owner and the lessee. These royalties are not eligible for incentive programs sponsored by various governments as discussed

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below. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production, and the rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery and the type or quality of the petroleum product produced.

From time to time the governments of Canada and the provinces have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and natural gas exploration or enhanced recovery projects. The trend in recent years has been for provincial governments to allow such incentive programs to expire without renewal, and consequently few such incentive programs are currently operative.

Oil royalty rates vary from province to province. In Alberta, oil royalty rates vary between 10% and 35% for oil and 10% and 30% for new oil. New oil is applicable to oil pools discovered after March 31, 1974 and prior to October 1, 1992. The Alberta government introduced the Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992.

Effective January 1, 1994, the calculation and payment of natural gas royalties became subject to a simplified process. The royalty reserved to the Crown, subject to various incentives, is between 15% and 30%, in the case of new gas, and between 15% and 35%, in the case of old gas, depending upon a prescribed or corporate average reference price. Natural gas produced from qualifying exploratory natural gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 continues to be eligible for a royalty exemption for a period of 12 months, or such later time that the value of the exempted royalty quantity equals a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible natural gas wells spudded or deepened to a depth below 2,500 metres is also subject to a royalty exemption, the amount of which depends on the depth of the well.

Oil sands projects are subject to a specific regulation made effective July 1, 1997 and expiring June 30, 2007, which, among other things, determines the Crown’s share of crude and processed oil sands products.

In Alberta, a producer of oil or natural gas from Crown lands is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC program. The ARTC program is based on a price-sensitive formula, and the ARTC rate currently varies 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 currently applied to a maximum of $2,000,000 of Alberta Crown royalties payable for each producer or associated group of producers. Crown royalties on production from producing properties acquired from corporations claiming maximum entitlement to ARTC will generally not be eligible for ARTC. The rate is established quarterly based on the average “par price”, as determined by the applicable government department for the previous quarterly period. On December 22, 1997, the Alberta government announced that it would conduct a review of the ARTC program with the objective of setting out better targeted objectives for a smaller program and to deal with administrative difficulties. On August 30, 1999, the Alberta government announced that it would not be reducing the size of the program, but that it would introduce new rules to reduce the number of persons who qualify for the program. The new rules will preclude companies that pay less than $10,000 in royalties per year and non-corporate entities from qualifying from the program.

Producers of oil and natural gas in British Columbia are required to pay annual rental payments in respect of Crown leases and royalties and freehold production taxes in respect of oil and gas produced from Crown and freehold lands, respectively. The amount payable as a royalty in respect of oil depends on the vintage of the oil (whether it was produced from a pool discovered before or after October 31, 1975), whether the oil is considered incremental or produced from a well shut-in for at least 36 months immediately preceding January 1, 1998 and which resumed production on or after such date, the quantity

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of oil produced in a month and the value of the oil. Oil produced from pools discovered after June 30, 1974 may be exempt from the payment of a royalty for the first 36 months of production. Subject to the minimum royalties described in the following sentence, the royalty payable on natural gas is determined by a sliding scale based on a reference price, which is the greater of the amount obtained by the producer and a prescribed minimum price. Gas produced in association with oil has a minimum royalty of 8% while the royalty in respect of other gas may not be less than 15%.

Oil and natural gas royalty holidays and reductions for specific wells reduce the amount of Crown royalties paid to the provincial governments. The ARTC program provides a rebate on Crown royalties paid in respect of eligible producing properties.

Environmental Regulation

The oil and natural gas industry is subject to environmental regulation pursuant to local, provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions and regulation on the storage and transportation of various substances produced or utilized in association with certain oil and gas industry operations and can affect the location and operation of wells and facilities and the extent to which exploration and development is permitted. In addition, legislation requires that well and facilities sites be abandoned and reclaimed to the satisfaction of provincial authorities. As well, applicable environmental laws may impose remediation obligations with respect to property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures and a breach of such legislation may result in the suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, the imposition of fines and penalties or the issuance of clean-up orders. Applicable environmental laws in Alberta are consolidated in theEnvironmental Protection and Enhancement Act. Under this Act, environmental standards and compliance for releases, clean up and reporting are stricter and more onerous than the previous legislation. Also, the range of enforcement actions available and the severity of penalties have been significantly increased. These changes will have an incremental effect on the cost of conducting operations in Alberta.

British Columbia’sEnvironmental Assessment Act became effective June 30, 1995. This legislation rolled the previous processes for the review of major energy projects into a single environmental assessment process with public participation in the environmental and review process.

We are committed to meeting our responsibilities to protect the environment wherever we operate and anticipate making increased, although not material, expenditures of both a capital and expense nature as a result of increasingly stringent laws relating to the protection of the environment.

All government regulations and procedures will be followed in strict adherence to the law. We believe in well abandonment and site restoration in a timely manner to ensure minimal damage to the environment and lower overall costs to us.

C. Organizational Structure

The Company has no subsidiaries.

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D. Property, Plant and Equipment

Principal Producing Properties of the Company

The following is a summary and description of our principal oil and natural gas properties as at December 31, 2004. All of our producing properties are located in Alberta, Canada. All references to reserves and production are working interest numbers after deduction of royalties payable to others. Reserve amounts have been obtained from the GLJ Report. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2004.

Property Name	Average Working Interest		Major Product	2004 Average Net Production (BOE/d	)	Proved Reserves (MBOE	)	Probable Reserves (MBOE	)	Proved +  Probable Reserves (MBOE	)
Marten Creek	100	%	Gas	521		1,673		682		2,355
Bassano	48	%	Oil & Gas	53		57		23		80
Bashaw	100	%	Oil & Gas	39		182		21		203
Bernadet	50	%	Gas	-		62		13		75
Other	Various		Gas	3		200		67		267
Total				616		2,174		806		2,980

Marten Creek, Alberta

Marten Creek, our first core area, accounted for approximately 85% of our production in 2004. Marten Creek is a relatively shallow (1,925 feet) multi-zone Cretaceous natural gas area located about 300 miles north of Calgary and it is 100% owned and operated by us. During the first quarter of 2004, we drilled ten wells with eight successes. In addition, we constructed four miles of eight-inch group flowline with a 50% joint interest partner and participated (30% working interest) in a 1500HP field compressor.

Initial gas production from seven wells commenced in March 2004 at 4.5 MMcfpd and was gradually increased during the year to over 6 MMcfpd reflecting the higher deliverability capability from the wells and the expansion of third party processing facilities. Production in the area averaged 3.8 MMcfpd for 2004 or 635 boe/d.

Our land position has almost tripled over the past year to an average 85% interest in some 38,000 acres. We also hold an additional 8,320 acres under option. We have accumulated a seismic base of 770 miles of 2D seismic data on which over 35 potential drilling locations have been identified on existing lands. Based on that information, a second multi-well program was commenced in late December 2004 with 24 wells drilled by the end of February 2005 resulting in 18 cased wells. Well testing is underway and thus far at least half of the wells are each capable of producing over 1 MMcfpd. Pipelining is in progress and two additional field compressors (400HP and 600HP) are being installed. In addition to gathering lines, we are building a nine mile, 6 inch, group flowline. This is a winter work area and all work must be completed by the end of March, which is generally the start of spring break-up.

Initial results from the winter program are encouraging and we are on target to double our current production from 6 MMcfpd to 12 MMcfpd (2,000 boe/d) in the second quarter. We will continue to expand our position in the area and another multi-well drilling program is planned for next winter.

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Bernadet, British Columbia

Bernadet is located about 65 miles west of the Alberta border in north-eastern British Columbia. This is a new exploration project developed by us on which we drilled a gas discovery in December which tested at 1.5 MMcfpd on completion. It appears to be in a gas charged fairway and we potentially have four to eight additional drilling locations. We operate this project with a 50% interest in 7,260 acres on the play. Our target here is Bluesky gas at a depth of 3,500 feet with reserve potential of 1 to 3 Bcf per well.

A two-mile pipeline and a field compressor are being constructed to the main line in order to place the discovery well on production. An offset well is also planned prior to spring break-up which would also be pipeline connected. Additional drilling is planned for the summer and fall of 2005.

Bassano, Alberta

This property is located 90 miles southeast of Calgary. We hold an average 48% working interest in six producing Belly River gas wells and a 50% working interest in a producing Glauconite oil well. We also hold an average 46% working interest in Belly River gas rights underlying 3,840 total gross acres of land. We have no development plans for this area in 2005. Current production is approximately 54 boe/d.

Bashaw, Alberta

Bashaw is located approximately 110 miles northeast of Calgary. In 2003, our working interests comprised 100% in two producing light gravity Nisku oil wells plus 100% in 880 acres of undeveloped lands. We have no development plans for this area in 2005. Current production is approximately 74 boe/d.

The foregoing properties account for 91% of our total proven plus probable reserves. The remaining reserves consist of minor interests in various areas in Alberta.

Drilling Activity

The following table summarizes the results of our drilling activity for each of the last two fiscal years.

	2004				2003
	Gross		Net			Gross		Net
Gas	11		10			1		1.0
Oil	-		-			-		-
Dry	4		3.5			-		-
Total	15		13.5			1		1.0
Exploratory	11		10.5			1		1
Development	4		3.0			-		-
Total	15		13.5			1		1
Success Rate	73	%	73	%		100	%	100	%

Luke drilled 15 wells during 2004 with an average interest of 90%. The Company drilled 11 successful gas wells with nine at Marten Creek and two at Bernadet. The Company drilled four unsuccessful wells, one in Marten Creek, one in Bassano and two on exploratory projects in northeast B.C.

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In addition, two successful gas wells were drilled on farmouts in western Alberta at no cost to Luke. The Company has a 9.75% royalty interest until payout in each well which reverts to a 26% interest payout.

Land Holdings

During the past year Luke was an active participant at Crown land sales. The Company focused on expanding its acreage position in its core area of Marten Creek, Alberta and on acquiring prospective acreage in new exploration areas. As a result Luke's undeveloped land inventory has doubled to 33,319 net acres (as compared to 16,600 net acres in 2003). The Company now holds an average 81% interest in 41,168 gross undeveloped acres.

Luke's undeveloped lands were valued at $7.87 million by the independent land consulting firm of Seaton-Jordan & Associates Ltd. in their year-end report. This is up from the $2.92 million attributed to Luke's lands in the Seaton-Jordan report of a year ago.

Luke will continue to build its undeveloped land inventory in 2005 as the Company’s exploration team develops other new exploration areas.

	2004				2003
Acres		Gross	Net			Gross	Net
Alberta		33,920	27,721			20,500	16,600
British Columbia		7,248	5,598			-	-
Total		41,168	33,319			20,500	16,600
Value of net acres ($ millions)			$7.87				$2.92
Average working interest			81	%			81	%

Oil And Gas Wells

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2004.

	Oil Wells						Natural Gas Wells
	Producing			Non-Producing			Producing		Non-Producing
		Gross	Net		Gross	Net	Gross	Net	Gross	Net
Alberta		3.0	2.5		-	-	22	14.14	11.0	3.7
British Columbia		-	-		-	-	-	-	2.0	1.0
Total		3.0	2.5		-	-	22	14.14	13.0	4.7

Notes:

(1) "Gross" refers to all wells in which we have an interest and "Net" refers to the aggregate of the percentage interest we have in the Gross Wells.

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Reserves

Summary of Oil and Gas Reserves

Working Interest after Royalties

at Constant Prices and Costs

	December 31, 2004(1)		January 1, 2004(1)		January 1, 2003(2)
	Oil and Liquids (Mbbl)	Natural Gas (Mmcf)	Oil and Liquids (Mbbl)	Natural Gas (Mmcf)	Oil and Liquids (Mbbl)	Natural Gas (Mmcf)
Proved-Developed	219	11,190	207	842	184	899
Proved-Undeveloped	2	607	-	-	-	-
Total Proved	221	11,797	207	842	184	899
Probable(3)	39	4,632	28	922	18	221
Total	260	16,429	235	1,764	202	1,120

Notes:

(1) Evaluation of the reserves was prepared in accordance with Canadian National Instrument 51-101.

(2) Evaluation of the reserves was prepared in accordance with Canadian National Policy 2B definitions and accordingly probable reserves were adjusted for risk (50%).

(3) The SEC generally prohibits the inclusion of estimates of probable reserves in filings with the SEC. However, probable reserves are included in Canadian securities filings and are provided here for information only.

Production

The following production information is net before the payment of royalties.

	Year Ended December 31, 2004		Period Ended December 31, 2003		Period Ended(1) December 31, 2002
	Oil and NGL's(Bbl)	Gas (Mmcf)	Oil and NGL's (Bbl)	Gas (Mmcf)	Oil and NGL's (Bbl)	Gas (Mmcf)
Canada	21	1,231	19	88	24	11

Notes:

(1) Production history for the Retained Assets transferred to the Company on February 26, 2003.

ITEM 5 OPERATING AND FINANCIAL REVIEW PROSPECTS

The following section contains forward-looking statements that involve risks and uncertainties. Such information, although considered reasonable by the Company at the time of preparation, may prove to be inaccurate and actual results may differ materially from those anticipated in the statements made.

The following discussion and analysis of financial results should be read in conjunction with the audited financial statements of the Company for the year ended December 31, 2004, together with the notes related thereto. The discussion contains forward-looking statements that involve risks and uncertainties. Such information, although considered reasonable by Luke management at the time of preparation, may prove to be inaccurate and actual results may differ materially from those anticipated in the statements made.

The Company evaluates its performance based on earnings and cash flow. Cash flow is a non-GAAP (Generally Accepted Accounting Principle) term that represents earnings before depletion, depreciation and accretion, future income taxes and stock-based compensation. Cash flow per share is calculated using the same weighted average number of shares outstanding as earnings per share. The non-GAAP measure is not standardized and therefore may not be comparable to similar measures byother entities. It is a key measure as it demonstrates the Company’s ability to generate cash necessary to fund future growth through capital investment. Cash provided by operating activities is the GAAP term. The difference between the GAAP and the non-GAAP term is the change in non-cash working capital items.

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In this discussion and analysis, certain natural gas volumes have been converted to barrels of oil equivalent (BOE) on the basis of six thousand cubic feet (6 Mcf) to one barrel (1 Bbl). BOE 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 equivalency at the well head.

Critical Accounting Estimates

Significant accounting policies are contained in note 2 to the financial statements. The following discusses the accounting estimates that are critical in determining the reported financial results:

Full Cost Accounting

The Company follows the full cost method of accounting as prescribed by Accounting Guideline # 16 issued by the CICA. All costs for exploration and development of reserves are capitalized in a single cost centre. The costs are depleted on the unit-of-production method based on estimated proven reserves. The capitalized costs may not exceed a ceiling amount. If the net capitalized costs are determined to be in excess of the calculated ceiling, which is normally a reserve-based estimate, the excess must be expensed. Proceeds on disposal of properties are deducted from such costs without recognition of a gain or loss except where such disposal is a significant portion of the reserves.

An alternative method of accounting of oil and natural gas operations is the successful efforts method. A major difference in applying the successful efforts method is that exploratory dry holes and geological and geophysical exploration costs are charged against earning as incurred rather than being capitalized. Also, under this method the cost centre is defined to be a property rather than a country cost centre.

Reserves

The Company engages independent petroleum engineering consultants to evaluate its reserves.

Reserve determinations involve forecasts based on property performance, future prices, projected future production and the timing of future capital expenditures, all of which are subject to uncertainties and interpretations. Reserve estimates have a significant impact on reported financial results as they are the basis for the calculation of depreciation and depletion and many non-GAAP key performance indicators.

Revisions can change reported depletion and depreciation and earnings; downward revisions could result in a ceiling test write-down.

Asset Retirement Obligation

The Company provides for the estimated abandonment costs of properties using a fair value method. This future estimate is based on estimated costs and technology following current legislation and industry practice. The reported liability is a discounted amount. The amount of the liability is affected by factors such as the number of wells, the timing of the expected expenditures and the discount factor. These estimates will change and the revisions could impact the depletion and depreciation rates.

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A. Operating Results

Production and Revenue

Luke’s gas production increased significantly to 4.1 MMcfpd in 2004 from 380 Mcfpd in 2003 due to the drilling success at Marten Creek in the first quarter of 2004. As a result of increased production, oil and gas revenues increased over sixfold to $10.7 million from $1.7 million in 2003. In addition, the Company’s oil and gas revenues benefited by the 5% higher commodity prices on a barrel equivalent basis. The Company’s average oil price was $47.77 per bbl (2003 - $35.08 per bbl) while gas averaged $6.25 per Mcf (2003 - $6.47 per Mcf).

Production volumes in the fourth quarter of 2004 were 1,047 boepd versus 137 boepd in the fourth quarter of 2003 as a result of the increased production from Marten Creek. Fourth quarter oil and gas revenues totalled $3.6 million as compared to $0.4 million for the comparable quarter in 2003. Oil and gas prices in the fourth quarter of 2004 were also higher than in the fourth quarter of 2003. The Company’s oil price averaged $51.64 per bbl (Q4 2003 - $33.88 per bbl) and the gas price averaged $6.11 per Mcf (Q4 2003 - $5.57 per Mcf).

Royalties

($000's)		2004			2003
Crown royalties	$	2,091		$	-
Other royalties		404			435
Alberta Royalty Tax Credit		(486	)		-
Net royalties	$	2,009		$	435
Average royalty rate as a percentage of oil and gas revenues		19	%		25	%

Net royalties increased to $2 million from $435,000 last year due to the higher production volumes. The lower average royalty rate of 19% compared to 25% in 2003 is attributable to the gas production at Marten Creek which is eligible for the Alberta Royalty Tax Credit and a reduced crown rate based on production levels.

Fourth quarter net royalties were $727,000 as compared to $110,000 in the fourth quarter of 2003. The increase is due to the higher production volumes quarter over quarter.

Operating Expenses

Operating expenses were up from $263,000 ($5.61 per boe) for the period ended December 31, 2003 to $2 million ($7.16 per boe) in 2004. The main increase in operating costs was at Marten Creek which averaged $6.80 per boe for the year. These costs are primarily from third party transportation and processing fees. The remainder of the increase is due to the increased per unit costs at Bashaw and Bassano where production has declined, however fixed costs remain unchanged.

The fourth quarter operating expenses for 2004 were $618,000 as compared to $79,000 in the fourth quarter of 2003. The increase is due to the Company’s growth in production.

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General and Administrative Expenses

General and administrative expenses for the year ended December 31, 2004 were $2.0 million as compared to $1.1 million in 2003. As a result of increased production, general and administrative expenses were down to $7.06 per boe for the year as compared to $24.06 in 2003. The Company has the staffing in place to manage a much larger production base with minimal incremental costs.

Depletion, Depreciation and Asset Retirement Obligation

The annual provision for depletion, depreciation, and accretion increased to $2.4 million from $489,000 in 2003. The average cost in 2004 was 24% lower at $8.48 per boe as compared to $10.54 per boe in 2003. The fourth quarter provision for depletion, depreciation and accretion was $925,140 ($9.61 per boe) as compared to $161,275 ($12.78 per boe) in the fourth quarter of 2003. The per barrel of oil equivalent decreases year over year result from the successful drilling program at Marten Creek.

The following table summarizes the expense:

($000’s)		2004		2003
Depletion of petroleum and natural gas properties	$	2,261	$	463
Depreciation of office furniture and equipment		84		26
Accretion of asset retirement obligation		13		4
Total depletion, depreciation, and accretion	$	2,358	$	493

Included in the depletion of petroleum and natural gas properties is $44,175 (8,416 in 2003) representing the depletion on the capitalized retirement obligation of $491,460 ($106,460 in 2003).

Taxes

The current tax expense for the year ended December 31, 2004 is only $5,000 versus $96,800 in 2003. This provision relates exclusively to the Federal Large Corporations Tax. In 2003 the Company did not qualify for the capital base exemption because it was taken by KeyWest Energy Corporation, the former parent company.

The provision for future taxes of $1.1 million is 49% of pre-tax earnings as compared to $290,000 in 2003 or 38% of pre-tax earnings. The lower rate for 2003 is due to the gain on sale of the Government of Canada bonds resulting in a capital gain which is only 50% taxable.

At the end of 2004, the Company had approximately $28 million of accumulated tax pools that are available for deduction against future earnings.

		$000’s	Annual Deduction Rate
Canadian exploration expense	$	3,656	100	%
Canadian development expense		3,028	30	%
Canadian oil & gas property expense		13,436	10	%
Undepreciated capital cost		6,326	20% - 30	%
Share issue costs		1,629	20	%
Non-capital losses		148	100	%
	$	28,223

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Cash Flow and Earnings

Luke’s cash flow increased 280% to $5.2 million ($0.15 per share) in 2004 from $1.4 million ($0.05 per share) for the period ended December 31, 2003. The higher cash flow reflects the production growth generated by the successful drilling program at Marten Creek. Cash flow in 2003 also included a one-time $505,000 gain on the sale of marketable securities.

Fourth quarter cash flow was also up significantly to $1.9 million from $247,195 in the fourth quarter of 2003 as a result of higher gas production.

The Company’s fourth quarter and annual earnings were also up significantly compared to in the fourth quarter of 2003 as a result of the higher gas production.

Capital Expenditures

($000’s)		2004		2003
Land	$	7,408	$	2,077
Seismic		3,192		1,064
Drilling and equipping		8,478		953
Facilities and flowlines		4,608		565
Pipe and casing inventory		2,210		-
Property acquisitions		2,707		-
Corporate		215		176
	$	28,818	$	4,835

The increase in capital expenditures to $28.8 million in 2004 from $4.8 million in 2003 reflects increased activity levels. The Company drilled 15 gross (13.5 net) wells in 2004 as compared to one well in 2003. Land and seismic costs were higher than last year due to the expansion of the Marten Creek area as well as generating new prospect areas. In addition, the Company completed two minor property acquisitions during the year; one at Bashaw where the Company bought out its 50% partner in two wells and the second was in the southeastern part of Marten Creek where a small interest was acquired in several wells plus an interest in a pipeline and compressor which will be used to expand the Company’s program.

The Company also incurred $2.2 million of costs in December for purchasing pipe and casing for the 2005 Marten Creek drilling program. It was necessary to secure these materials in advance as supply shortages were expected given the record drilling activity.

Financial Reporting and Regulatory Changes

New and amended standards described below were implemented by the Company in 2004 with the following impact:

Stock-based Compensation

On January 1, 2004 the Company adopted the amended CICA standard for “Stock based compensation and other stock based payments.” The amendment requires that companies measure all stock based payments using the fair value method of accounting and recognize the compensation expense

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in their financial statements. The fair value was estimated using the Black-Scholes option pricing model. The Company applied the change in policy retroactively with restatement of prior period financial statements. The change resulted in a reduction in earnings of $698,113 ($0.02 per share) for the year ended December 31, 2004 and $214,092 ($0.01 per share) for the period ended December 31, 2003.

Certain new and amended standards are expected to impact the Company in 2005 as follows:

Reporting on Internal Control over Financial Reporting

In February of 2005, the Ontario Securities Commission released a draft National Instrument 51-111 “Reporting on Internal Control over Financial Reporting”. The instrument proposes a requirement for reporting issuers to complete an internal control evaluation and have their external auditors give an opinion on the Company’s internal control in conjunction with the year-end audit. This proposed legislation will be substantially consistent with the United States Securities Commission (“SEC”) rules as outlined in section 404 of the Sarbanes-Oxley Act. The proposed legislation would require Luke Energy, based on current market capitalization, to complete their internal control evaluation by December 31, 2008. However, Luke Energy is a Foreign Private Issuer and files a Form 20-F with the SEC. Accordingly, under the Sarbanes-Oxley Act in the United States, the CEO and CFO of Luke Energy have been filing “Bare” certificates since the first quarter of 2003 with their financial statements. For the Company’s year-end filing for 2006, the CEO and CFO will be required to file “Full” certificates. This will require the Company to complete an internal control evaluation before December 31, 2006 and have the Company’s independent auditors provide an opinion on management’s process for evaluating the internal controls and their effectiveness at December 31, 2006.

B. Liquidity and Capital Resources

The Company is well capitalized for growth with working capital of $17.2 million as at December 31, 2004 and an unused $16 million credit facility (See Note 5 to the Financial Statements). The 2005 capital expenditure program of $46 million will be funded by working capital, cash flow (forecasted at $14.5 million for 2005) and credit facility borrowings.

During 2004 the Company issued a total of 2.1 million Common Shares on a tax flow-through basis for gross proceeds of $5.7 million. Management and directors subscribed for approximately 20% of the issued stock.

At April 30, 2005, the Company had 37,002,893 Common Shares outstanding and 3,239,333 stock options outstanding. At December 31, 2004 the Company had 36,997,823 Common Shares outstanding. In addition, the Company had 3,214,333 stock options outstanding at an average exercise price of $1.69 per share. Options vest equally over three years and have a five year term. At year-end 846,667 options were exercisable at an average exercise price of $1.55.

At December 31, 2004, the Company had a remaining commitment to expend approximately $5.5 million on exploration drilling and seismic. The capital spending in the first quarter of 2005 was sufficient to satisfy this obligation.

C. Research and Development

The Company does not have any research and development policies, nor has it incurred any expenses since incorporation in relation to company-sponsored research and development activities.

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D. Trend Information

There are a number of trends that have been developing in the oil and gas industry during the past several years that appear to be shaping the near term future of the business.

Commodity Prices

Natural gas is a commodity influenced by factors within North America. The continued tight supply demand balance for natural gas is causing significant elasticity in pricing. Despite record drilling activity, a strong economy, weather, fuel switching and demand for electrical generation there still exists concerns about storage inventory levels and uncertainty in supply prospects. Prices for 2005 are forecast to remain in the Cdn $5.75 to $6.50/Mcf range.

Crude oil is influenced by the world economy and OPEC’s ability to adjust supply to world demand. Oil prices in 2003 and 2004 were kept high by political unrest and supply disruptions. More recently, higher world demands combined with lower inventory levels are responsible for the current price strength. Crude oil prices for 2005 are forecast to be in the US $40 to $43/bbl range.

The impact on the oil and gas industry from commodity price volatility is significant. During periods of high prices, producers generate sufficient cash flows to conduct active exploration programs without external capital. Increased commodity prices frequently translate into very busy periods for service suppliers triggering premium costs for their services. The cost of purchasing land and properties similarly increase during these periods. During low commodity price periods, acquisition costs drop, as do internally generated funds to spend on exploration and development activities. With decreased demand, the prices charged by the various service suppliers also decline.

Industry Consolidation and Competition

Over the past few years, consolidation within the Canadian oil and gas industry has resulted in a significant reduction of the number of junior to intermediate-sized exploration and production companies. American companies have also been acquiring companies and assets in Canada. The strength in commodity prices is expected to result in a continued high level of corporate and asset transactions as buyers strive to increase their asset base and sellers take advantage of high transaction prices.

Along with this merger and acquisition activity, a number of traditional exploration and production companies have recently converted into income or royalty trusts. This trend, which has increased competition for investment dollars and property acquisitions, is expected to continue in the near-term.

Strong commodity prices have increased operating cash flows leading to increased drilling activity. 2004 was another record year for the drilling and related service companies. This level of activity increases competition for oilfield goods and services and may cause drilling and operating costs to increase.

Capital Markets

Generally during the past two years, the economic recovery combined with increased commodity prices has caused an increase in new equity financings in the oil and gas industry. We compete with the numerous new companies and their new stories in obtaining access to capital. The competitive nature of the oil and gas industry will cause opportunities for equity financings to be selective. Some companies will have to rely on internally generated funds to conduct their exploration and developmental programs.

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E. Off-balance Sheet Arrangements

The Company has no off-balance sheet arrangements.

F. Disclosure of Contractual Obligations

The following table summarizes the expected payments under our outstanding contractual obligations at December 31, 2004.

		Total		2005		2006-2007		2008-2009		After 2009
	(In Millions)
Long term debt	$	-	$	-	$	-	$	-	$	-
Capitalized leases		-		-		-		-		-
Operating leases		1.1		0.2		0.4		0.4		0.1
Purchase obligations		-		-		-		-		-
Other Long-Term Liabilities		-		-		-		-		-
Total	$	1.1	$	0.2	$	0.4	$	0.4	$	0.1

G. Safe Harbor

See the discussion under the caption "Forward-Looking Statements" in the preamble to this report.

ITEM 6 DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES

A. Directors and Senior Management

The following table sets forth the names of the directors and members of senior management of the Company, their positions and offices with the Company, their principal business activities performed outside the Company (as to directors), employment history and their terms of office.

Name and Municipality of Residence	Office Held	Principal Occupation	Director Since
Ronald Belsher(1)(2) Calgary, Alberta	Director	Partner in Collins Barrow Calgary LLP, Chartered Accountants since 1977.	January 9, 2003
Mary Blue Calgary, Alberta	Vice - Chairman of the Board and Director	Vice-Chairman of the Board of the Company since October 14, 2004. Prior thereto, President and Chief Operating Officer of the Company; prior thereto, Executive Vice-President of KeyWest Energy Corporation from February 1998 to February 2003; prior thereto, Sr. Vice-President, Land of Calgary-based Jordan Petroleum Ltd. from March 1993 to February 1998.	January 9, 2003

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Name and Municipality of Residence Office Held Principal Occupation Director Since

David Crevier(1)(3) Montreal, Quebec	Director	Partner in the Montreal law firm of Colby, Monet, Demers, Delage & Crevier LLP. Mr. Crevier is also a director of Yorbeau Resources Inc., Cancor Mines Inc., Diagem Inc. and Diagnos Inc.	January 9, 2003
Alain Lambert(2) West Bolton, Quebec	Director	Managing Partner of Canadian Public Venture Capital Group since March 2003. President of One and Company Communications since February 2002. Managing Partner of Triology Integrated Investor Relations Inc. from July 1998 to May 2001. Mr. Lambert is also a director of ExcelTech Aerospace Inc., Damian Capital Inc., Canadian Public Venture Capital I Inc., CPVC Tremblant Inc. and Allen-Vanguard Corporation.	January 9, 2003
Hugh Mogensen(1) Saanichton, BC	Chairman of the Board andDirector	Independent Business Executive serving as a Board member for several natural resource companies since 1986. Mr. Mogensen is also Chairman & CEO of Pelesys Learning System Inc. a director of Goose River Resources and Queenstake Resources and a member of the Advisory Board of Altius Minerals Inc.	January 9, 2003
Harold V. Pedersen(2) Calgary, Alberta	President & CEO and Director	President and Chief Executive Officer of the Company; prior thereto, President of KeyWest Energy Corporation from February 1998 to February 2003; prior thereto, President of Jordan Petroleum Ltd. from August 1986 to December 1997.	January 9, 2003
Lyle Schultz(3) Calgary, Alberta	Director	Independent businessman; prior thereto, Vice-President and co-founder of MiCasa Rentals Inc., a privately owned oilfield wellsite trailer rental company from 1993 to 2004. Mr. Schultz is also a director of International Tech Corp.	January 9, 2003
J. Ronald Woods(1)(3) Toronto, Ontario	Director	President of Rowood Capital Corp. since November 2000; prior thereto, Vice-President of Jascan Resources Inc. since 1996. Mr. Woods is also a director of Regal Energy Corp., Virtus Energy Ltd. and Zoom Telephonics, Inc.	January 9, 2003
Kevin Lee Calgary, Alberta	Vice-President, Engineering	Vice-President, Engineering of the Company since June 2003. Mr. Lee was formerly the Production Group Leader for Brooks North with EnCana Corporation and prior thereto, was manager of Reservoir Engineering at Star Oil & Gas Ltd.

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Name and Municipality of Residence Office Held Principal Occupation Director Since

Rob E. Wollmann Calgary, Alberta	Vice-President, Exploration	Vice-President, Exploration of the Company since April 2003. Mr. Wollmann was formerly with RioAlto Exploration from 1993 to 2002 - most recently as Vice-President of Exploration and as Exploration Manager prior thereto.
Carrie McLauchlin, Calgary, Alberta	Vice-President, Finance and Chief Financial Officer	Vice-President, Finance and Chief Financial Officer of the Company since February 2003. Prior thereto, Ms. McLauchlin was the Vice-President Finance and Chief Financial Officer of KeyWest Energy Corporation, having joined KeyWest in June 1999 as Accounting Manager. Ms. McLauchlin received her C.A. designation in 1990 with the firm of KPMG LLP where she worked from 1987-1997 (Senior Audit Manager in her last three years).
Peter W. Abercrombie Calgary, Alberta	Vice-President, Land	Vice-President, Land of the Company since December 2003. Prior thereto, Mr. Abercrombie was the Land Group Leader for the Fort Nelson Business Unit with EnCana Corporation since May 2002. Prior thereto, Mr. Abercrombie was the Land Group Leader for the North East Business Unit of Alberta Energy Corporation Ltd.
Chris von Vegesack Calgary, Alberta	Corporate Secretary	Partner at Burnet, Duckworth & Palmer LLP, a Calgary based law firm, since 1986.

Notes:

(1) Member of the Audit and Reserves Committee.

(2) Member of the Compensation Committee.

(3) Member of the Governance Committee.

The individuals named above are not related by blood or marriage. There are no arrangements or understanding with major shareholders, customers, suppliers or others, pursuant to which any person referred to above was selected as a director or member of senior management.

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B. Compensation

The following table outlines the compensation paid or payable, stock options and Common Shares held for directors and management of the Company for the fiscal year-ended December 31, 2004.

	Compensation				Securities Under Option (1)					Common Shares Owned
Name and Position with Company		Salary (Cdn$)		Other(2) (Cdn$)		Number of Options		Exercise Price	Expiry Date		Number		% Owned
Harold V. Pedersen	$	84,171	$	2400		60,000	$	0.81	Feb. 19, 2008		1,863,678		5.04
President & CEO and Director						150,000	$	1.76	Aug. 26, 2008
Carrie McLauchlin, CA	$	83,771		-		60,000	$	0.81	Feb. 19,2008		276,709		0.75
V.P. Finance & CFO						100,000	$	1.76	Aug. 26,2008
Remaining Directors	$	393,342	$	21,600		410,000	$	0.81	Feb. 19, 2008		3,571,993(3	)	9.65
and Officers						970,000	$	1.76	Aug. 26, 2008
						200,000	$	1.76	Nov. 3, 2008

Notes:

(1) There are no outstanding restricted shares or units and the Company does not have a long-term incentive plan, pension plan or other compensatory plan for its executive officers. The underlying securities for all options are the Company's Common Shares and all options were obtained from grants by the Company.

(2) Other compensation includes director fees and bonuses.

(3) No individual ownership exceeded 3%.

C. Board Practices

Tenure of Board of Directors

All directors have served since January 9, 2003 and they stand for election at each annual meeting of the Company. All directors were re-elected at the annual meeting held on May 19, 2004.

Service Contracts

The Company currently does not have any service contracts that provide for benefits upon termination of employment.

Audit Committee

The Audit Committee is comprised of Ronald L. Belsher, David Crevier, Hugh Mogensen and J. Ronald Woods, all of whom are “outside” directors.

The Audit Committee meets quarterly in each year and among other things, with the assistance of the external auditors, is responsible for reviewing management programs and policies regarding the adequacy and effectiveness of the internal controls over the accounting and financial reporting systems within the Corporation, including management’s response to internal control recommendations of the external auditors. The committee reviews management plans regarding changes in accounting practices and policies and the financial impact thereof and is responsible for reviewing the major areas of management judgment and estimates that have a significant effect upon the financial statements. The Audit Committee is also charged with reviewing and approving all bank credit facilities and other borrowing strategies presented by senior management including price hedging and foreign currency risk strategies of the Corporation. The committee receives a yearly report from the Corporation’s external auditors with respect to the Corporation’s financial control and information systems which comes to their attention during the course of conducting the year-end audit. Results of those reports are relayed by the committee to the full Board for its consideration. At least once a year, the Audit Committee meets with the Corporation’s external auditors without management being present and may do so at any time throughout the rest of the year. All financial statements, quarterly reports, and other financial information that are publicly disseminated are reviewed for approval by the committee prior to their release.

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In addition, the Audit Committee meets on a yearly basis with the independent engineers of the Corporation following their preparation of the Corporation’s year-end reserve and economic evaluation. This meeting takes place prior to finalization and shareholder dissemination of the reserve results at which time the engineers are required to review, in detail, their reserve analysis and to discuss, among other things, the qualifications of the engineers responsible for the reserve analysis, the process and methodology utilized in evaluating the Corporation’s reserves and the Corporation’s compliance with any emerging issues related to the preparation of reserve analysis. Following such meeting, management of the Corporation is invited to attend the meeting for the purpose of engaging in a complete property-by-property discussion with the Audit Committee and the independent engineers.

Audit Committee Charter

Purpose

The Audit Committee (the “Committee”) is a committee of the board of directors (the “Board”) of the Company to which the Board has delegated its responsibility for oversight of the nature and scope of the annual audit, management’s reporting on internal accounting standards and practices, financial information and accounting systems and procedures, financial reporting and statements and recommending, for approval of the Board, the audited financial statements, interim financial statements and other mandatory disclosure releases containing financial information. The primary objectives of the Committee are as follows:

1.To assist the directors in meeting their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Company and related matters;

2.To provide better communication between directors and external auditors;

3.To enhance the external auditor’s independence;

4.To increase the credibility and objectivity of financial reports; and

5.To strengthen the role of the outside directors by facilitating in depth discussions between directors on the Committee, management and external auditors.

Composition

The Audit Committee shall be comprised of three or more directors as determined by the Board of Directors, none of whom are members of management of the Company and all of whom are “unrelated directors” (as such term is used in the Report of the Toronto Stock Exchange on Corporate Governance in Canada) and “independent” (as such term is used in Multilateral Instrument 52-110 - Audit Committees (“MI 52-110”)). All of the members of the Audit Committee shall be “financially literate”. The Board of Directors has adopted the definition for “financial literacy” used in MI 52-110, which means the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of the issues that can reasonably be expected to be raised by the issuer’s financial statements. Audit Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Company or an outside consultant.

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The members of the Audit Committee shall be elected by the Board of Directors at the annual organizational meeting of the Board of Directors and remain as members of the Audit Committee until their successors shall be duly elected and qualified. Unless a Chair is elected by the full Board of Directors, the members of the Audit Committee may designate a Chair by majority vote of the full Audit Committee membership.

Meetings

1.At all meetings of the Committee, every question shall be decided by a majority of the votes cast. In case of an equality of votes, the Chairman of the meeting shall not be entitled to a second or casting vote.

2.The Chair shall preside at all meetings of the Committee, unless the Chair is not present, in which case the members of the Committee present shall designate from among the members present, the Chair for purposes of the meeting.

3.A quorum for meetings of the Committee shall be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee shall be the same as those governing the Board, unless otherwise determined by the Committee or the Board.

4.Meetings of the Committee should be scheduled to take place at least four times per year. Minutes of all meetings of the Committee shall be taken. The Chief Financial Officer shall attend meetings of the Committee, unless otherwise excused from all or part of any such meeting by the Chairman.

5.The Committee shall meet with the external auditor at least once per year (in connection with the preparation of the year end financial statements) and at such other times as the external auditor and the Committee consider appropriate.

6. Agendas, approved by the Chair, shall be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.

7. The Committee may invite such officers, directors and employees of the Corporation as it may see fit from time to time to attend at meetings of the Committee and assist thereat in the discussion and consideration of the matters being considered by the Committee.

8. Minutes of the Committee will be recorded and maintained and circulated to directors who are not members of the Committee or otherwise made available at a subsequent meeting of the Board.

9. The Committee may retain persons having special expertise and/or obtain independent professional advice to assist in fulfilling its responsibilities at the expense of the Corporation.

10. Any members of the Committee may be removed or replaced at any time by the Board and shall cease to be a member of the Committee as soon as such member ceases to be a director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy shall exist on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, each member of the Committee shall hold such office until the close of the next annual meeting of shareholders following appointment as a member of the Committee.

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11. Any issues arising from these meetings that bear on the relationship between the Board and management should be communicated to the Chairman of the Board by the Committee Chair.

Responsibilities and Duties

To fulfill its responsibilities and duties, the Audit Committee shall:

1. Review and update this Charter at least annually, as conditions dictate.

2. It is the responsibility of the Committee to oversee the work of the external auditors, including resolution of disagreements between management and the external auditors regarding financial reporting.

3. It is the responsibility of the Committee to satisfy itself on behalf of the Board with respect to Luke’s Internal Control Systems:

• identifying, monitoring and mitigating business risks; and

• ensuring compliance with legal, ethical and regulatory requirements.

4. It is a primary responsibility of the Committee to review the annual and interim financial statements of Luke and related management’s discussion and analysis (“MD&A”) prior to their submission to the Board for approval. The process should include but not be limited to:

• reviewing changes in accounting principles and policies, or in their application, which may have a material impact on the current or future years’ financial statements;

• reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;

• reviewing accounting treatment of unusual or non-recurring transactions;

• ascertaining compliance with covenants under loan agreements;

• reviewing disclosure requirements for commitments and contingencies;

• reviewing adjustments raised by the external auditors, whether or not included in the financial statements;

• reviewing unresolved differences between management and the external auditors; and

• obtain explanations of significant variances with comparative reporting periods.

5. The Committee is to review the financial statements, prospectuses, MD&A, annual information forms (“AIF”) and all public disclosure containing audited or unaudited financial information (including, without limitation, annual and interim press releases and any other press releases disclosing earnings or financial results) before their release and prior to Board approval. The Committee must be satisfied that adequate procedures are in place for the review of Luke’s disclosure of all other financial information and shall periodically access the accuracy of those procedures.

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6.With respect to the appointment of external auditors by the Board, the Committee shall:

• recommend to the Board the external auditors to be nominated;

• recommend to the Board the terms of engagement of the external auditor, including the compensation of the auditors and a confirmation that the external auditors shall report directly to the Committee;

• on an annual basis, review and discuss with the external auditors all significant relationships such auditors have with the Corporation to determine the auditors’ independence;

• when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change; and

• review and pre-approve any non-audit services to be provided to Luke or its subsidiaries by the external auditors and consider the impact on the independence of such auditors. The Committee may delegate to one or more independent members the authority to pre-approve non-audit services, provided that the members report to the Committee at the next scheduled meeting such pre-approval and the member(s) comply with such other procedures as may be established by the Committee from time to time.

7. The Committee shall review with the external auditors (and the internal auditor if one is appointed by Luke) their assessment of the internal controls of Luke, their written reports containing recommendations for improvement, and management’s response and follow-up to any identified weaknesses. The Committee shall also review annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of Luke and its subsidiaries.

8. The Committee shall review risk management policies and procedures of Luke (i.e. hedging, litigation and insurance).

9. The Committee shall establish a procedure for:

• the receipt, retention and treatment of complaints received by Luke regarding accounting, internal accounting controls or auditing matters; and

• the confidential, anonymous submission by employees of Luke of concerns regarding questionable accounting or auditing matters.

10. The Committee shall review and approve Luke’s hiring policies regarding partners and employees and former partners and employees of the present and former external auditors of Luke.

11. The Committee shall have the authority to investigate any financial activity of Luke. All employees of Luke are to co-operate as requested by the Committee.

12. The Committee may retain persons having special expertise and/or obtain independent professional advise to assist in filling their responsibilities at the expense of Luke without any further approval of the Board.

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Compensation Committee

The Board has appointed a Compensation Committee comprised of Ronald L. Belsher (Chairman), Alain Lambert and Harold Pedersen, of which Messrs. Belsher and Lambert are “non-management related” directors. The committee’s mandate is to formally make recommendations to the Board in respect of compensation issues relating to directors, senior management and staff of the Corporation, including recommending performance objectives and the compensation package for the President and Chief Executive Officer.

Report of the Compensation Committee

The Company’s compensation philosophy is aimed at attracting and retaining quality and experienced personnel, which is critical to the success of the Corporation. Employee compensation, including executive officer compensation, is comprised of three elements: base salary, short-term incentive compensation (being cash bonuses) and long-term incentive compensation (being stock options).

The Compensation Committee makes recommendations for executive compensation to the full Board for approval.

Base Salaries

The Company’s approach to base compensation is to offer salaries which are competitive when compared to those within the Company’s peer group of companies. Base salary ranges are determined following a review of comparative data of the Company’s peer group. Compensation is weighted more heavily towards long-term incentive compensation by way of the grant of stock options in order to align the interests of the Company’s executive officers and employees with the performance of the Company and the interests of its shareholders.

Short-Term Incentive Compensation - Bonuses

In addition to base salaries, the Company may award cash bonuses to employees of the Company, including executive officers. In determining the size of the bonus pool, if any, the Compensation Committee considers, (i) Common Share price performance; (ii) growth in cash-flow; and (iii) growth in asset value. The award of a bonus is determined, in the case of employees, by senior management of the Company and approved by the Compensation Committee. The Compensation Committee in consultation with the President establishes bonus levels for Vice-Presidents and the Compensation Committee in consultation with the Board establishes the President and Chief Executive Officer’s bonus. In the case of non-executive employees, bonuses are based on the employee’s contribution in adding share value and reducing costs and the employee's contribution to the achievement of overall corporate goals. As Luke is an emerging oil and gas company, no cash bonuses were awarded in 2004.

Long-Term Incentive Compensation - Stock Options

Individual stock options are granted by the Board on the recommendation of senior management, in the case of employees, and by the Compensation Committee, in the case of executive officers including the President and Chief Executive Officer. Stock options are intended to align executive and shareholder interests by attempting to create a direct link between compensation and shareholder return. Participation in the Company’s stock option plan rewards overall corporate performance, as measured through the underlying value of the Company’s shares.

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Stock options are normally awarded by the Board upon the commencement of employment with the Company based on the level of responsibility within the Company. Additional grants may be made periodically to ensure that the number of options granted to any particular individual is commensurate with the individual’s level of ongoing responsibility within the Company. Stock option grants are determined by factors including the number of eligible individuals currently under the option plan, the number of shares to be acquired under existing options relative to the issued and outstanding Common Shares and Luke’s future hiring plans.

D. Employees

At December 31, 2004, the Company had 17 full-time employees (14 as at December 31, 2003) at its Calgary based head office and 2 field contract operators (1 as at December 31, 2003). The head office employees' main categories of activity were as follows: 4 performed administrative functions, 1 performed accounting functions, 5 performed geology/engineering functions, and 7 performed management functions. At inception of the Company in February 2003, the Company had 8 employees. None of the Company's employees belongs to a labour union. The Company occasionally hires hourly employees on an "as needed" project basis.

E. Share Ownership

The following table outlines the stock options and Common Shares held by the directors and management of the Company as at April 30, 2005.

Name and Position with the Company	Number of Stock Options	Common Shares Owned
Harold V. Pedersen,President & CEO and Director	210,000	1,989,978 or 5.38% of the issued and outstanding Common Shares
Carrie McLauchlin, C.A.,V.P. Finance and CFO	160,000	276,709 or 0.75% of the issued and outstanding Common Shares
Remaining directors and officers	1,560,000	3,631,043 or 9.81% of the issued and outstanding Common Shares

Also see Item 6.B.

Stock Option Plan

The Company has adopted a stock option plan effective February 25, 2003, as amended on April 14, 2003 (the “Plan”), which was approved by the shareholders of the Company at a special meeting held on April 14, 2003, for directors, officers, employees and consultants of the Company and its subsidiaries and other persons who provide ongoing management and consulting services to the Company. The Plan currently limits the number of Common Shares that may be issued on exercise of options to 3,305,395 Common Shares (8.9% of the Company’s issued and outstanding Common Shares as at April 30, 2005), of which 46,667 Common Shares (0.13% of those outstanding as at April 30, 2005) have been issued on exercise of Options, Options to purchase 3,239,333 Common Shares (8.8% of those outstanding as at April 30, 2005) are outstanding and 19,395 Common Shares are available for future grants (0.05% of those outstanding as a April 30, 2005). Options granted pursuant to the Plan have a term not exceeding five (5) years and vest as to one-third (1/3) on each of the first, second and third anniversaries of the date of the grant and the Plan provides for accelerated vesting of options upon a “change of control” of the

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Company or the sale by the Company of all or substantially all of the property and assets of the Company. Options granted under the Plan are non-assignable. The exercise price of options granted under the Plan is determined by the Board of Directors of the Company at the time of the grant and may not be less than the closing trading price of the Common Shares on the TSX on the last trading day preceding the date of the grant.

Under the Option Plan, (i) the number of Common Shares issuable (or reserved for issuance) to any one person under the Option Plan, together with all other share compensation arrangements of the Company, must not exceed 5% of the outstanding issue of Common Shares; (ii) in the aggregate, no more than 10% of the outstanding issue of Common Shares (on a non-diluted basis) may be issuable (or reserved for issuance) at any time to Insiders under the Option Plan, together with all other share compensation arrangements of the Company; and (iii) the aggregate number of Common Shares issued to Insiders pursuant to the Option Plan and all other share compensation arrangements of the Company, within a one (1) year period, shall not exceed 10% of the outstanding issue of Common Shares (on a non-diluted basis).

In case of death of an optionee, Options terminate on the date determined by the Board of Directors of the Company which may not be more than six (6) months from the date of death and, if the optionee ceases to be a director, officer or employee of, or ceases to be providing ongoing management or consulting services to, the Company, Options terminate on the expiry of 90 days following the date that the optionee ceased to be a director, officer or employee of the Company or ceased to provide ongoing management or consulting services to the Company, as the case may be. In the case of a takeover bid for the outstanding Common Shares of the Company, the Company has the right to satisfy any obligations to an optionee in respect of any unexercised Options by paying to the optionee a cash amount equal to the difference between the exercise price of unexercised Options held and the fair market value of the securities to which the optionee would have been entitled to receive upon the exercise of unexercised Options.

Upon the exercise of any Options granted under the Option Plan, the optionee may elect to receive, with the consent of the Company, and in consideration for the disposition by the optionee of the right to receive Common Shares pursuant to such options and the termination thereof, the difference between, (i) the weighted average price per share for the Common Shares for the five (5) consecutive trading days ending on the last trading day preceding the date in question on The Toronto Stock Exchange (the "TSX"), and (ii) the exercise price of the option, which amount may be paid, at the election or deemed election of the optionee, in cash or in Common Shares, in accordance with the provisions of the Option Plan.

Formerly, under the policies of the TSX, share compensation arrangements (including the Plan) were required to have a fixed maximum number of securities available for issuance. On January 1, 2005, the TSX amended certain parts of the TSX Company Manual including amendments to share compensation arrangements (collectively, the “TSX Amendments”). The TSX Amendments provide, among other things, for the removal of the requirement for a fixed maximum number of securities issuable under a share compensation arrangement, thereby allowing issuers to have a rolling maximum number of securities based on a percentage of its outstanding securities. Further thereto, the Board of Directors of the Company has proposed to amend the Plan (subject to shareholder approval) to: (i) change the number of authorized but unissued Common Shares that may be subject to options granted under the Option Plan at any time to 10% of the number of outstanding Common Shares from time to time; (ii) to provide that any increase in the issued and outstanding common shares of the Corporation will result in an increase in the available number of common shares issuable under the Option Plan; (iii) to provide that any increase in the number of options granted under the Option Plan will, if exercised, make new grants available under the Option Plan; and (iv) to amend the definition of “Outstanding Common Shares” in the Option Plan to mean all the issued and outstanding common shares of the Corporation (on a non-diluted basis) that are outstanding immediately prior to the share issuance or grant of stock options in question pursuant to the Option Plan.

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The Board of Directors may amend or discontinue the Plan at any time, provided that no such amendment may, without the consent of the optionees, alter or impair any option previously granted and provided that any amendment to the Plan is subject to receipt of all necessary approvals of the TSX and the approval of the shareholders of the Company if required by such exchange.

ITEM 7 MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

A. Major Shareholders

To the knowledge of the management of the Company, no shareholder as at April 30, 2005 beneficially owns more than five percent (5%) of any class of the Company's voting securities except for Harold V. Pedersen, President & CEO of the Company (see Item 6B above). Mr. Pedersen does not have any different voting rights as compared to any other shareholder of the Company.

At April 30, 2005, 3,232,885 Common Shares (8.7%) were held by 72 registered holders in the United States. The Company is not listed for trading on any securities exchange in the United States.

To the best of its knowledge, the Company is not owned or controlled, directly or indirectly, by another corporation, a foreign government or any other natural or legal persons(s), severally or jointly.

The Company is not aware of any arrangements the operation of which may at a subsequent date result in a change of control of the Company.

B. Related Party Transactions

No material transactions have been effected or are presently proposed as at the date hereof between the Company and:

(a) enterprises that directly or indirectly through one or more intermediaries, control or are controlled by, or are under common control with, the Company;

(b) associates (any unconsolidated enterprise in which the Company has a significant influence or which has a significant influence over the Company);

(c) individuals owning, directly or indirectly, an interest in the voting power of the Company that gives them significant influence over the Company, and close members of any such individual's family;

(d) key management personnel, that is, those persons having authority and responsibility for planning, directing and controlling the activities of the Company, including directors and senior management of companies and close members of such individuals' families; and

(e) enterprises in which a substantial interest in the voting power is owned, directly or indirectly, by any person described in (c) or (d) or over which such a person is able to exercise significant influence including enterprises owned by directors of major shareholders of the company and enterprises that have a member of key management in common with the Company.

Nor have any loans been made by the Company to any of the persons listed in paragraphs (a) through (e) above as at the date hereof.

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ITEM 8 FINANCIAL INFORMATION

Luke's Financial Statements are stated in Canadian dollars (Cdn.$) and are prepared in accordance with Canadian GAAP, with a reconciliation to US GAAP included under Note 13 to the Financial Statements under Item 17. In this Form 20-F, unless otherwise specified, all amounts are expressed in Canadian dollars.

A.  Financial Information

Refer to Item 17, which contains the following financial statements:

• The Company’s audited balance sheets as at December 31, 2004 and 2003 and the audited statements of earnings, retained earnings and cash flows and related notes for the year ended December 31, 2004 and the period ended December 31, 2003.

• The audited statement of revenue and operating expenses of the Retained Assets to be transferred to the Company for each of the years in the three-year period ended December 31, 2002.

• The unaudited pro-forma statement of earnings for the years ended December 31, 2003 and 2002.

Legal Proceedings

To the Company’s knowledge, there are no legal or arbitration proceedings, including those relating to bankruptcy, receivership or similar proceeding and those involving any third party, that may have, or have had in the recent past, significant effects on the Company’s financial position or profitability.

Dividend Policy

To date, the Company has not paid, nor are there any plans to pay, dividends on any shares of the Company. Any decision to pay dividends in the future will be made by the Board of Directors and will be based on the Company’s earnings, financial requirements and other conditions at the time.

B. Significant Changes

No significant change has occurred since the date of the financial statements included herein.

ITEM 9 THE OFFER AND LISTING

Trading Information

Fiscal Year:	2004	2003
High Low	$3.35 $1.76	$2.65 $1.35

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2003 Quarterly:	Q1/03	Q2/03	Q3/03	Q4/03
High	$2.05	$2.65	$2.20	$1.90
Low	$1.35	$1.86	$1.65	$1.71

2004/2005 Quarterly:	Q1/04	Q2/04	Q3/04	Q4/04	Q1/05
High Low	$2.33 $1.76	$2.34 $1.99	$2.82 $2.10	$3.35 $2.46	$3.65 $2.76

Last 6 months:	Mar/05	Feb/05	Jan/05	Dec/04	Nov/04	Oct/04
High Low	$3.26 $2.76	$3.48 $3.00	$3.65 $3.11	$3.35 $2.77	$3.25 $2.46	$2.88 $2.59

The Company's Common Shares are listed and posted for trading on the Toronto Stock Exchange under the symbol "LKE".

ITEM 10 ADDITIONAL INFORMATION

A. Share Capital

Not Applicable.

B. Memorandum and Articles of Association

Company's objects and purposes

The Company was incorporated under theCanada Business Corporations Act (the "CBCA") under corporate access number 605289-4. The Company's Articles of Incorporation ("Articles") do not contain any limitations on its objects or purposes.

Director's power to vote on a proposal, arrangement or contract in which the director is materially interested

Under the CBCA, each director and officer of a corporation who is a party to a material contract or proposed material contract with the corporation or who is a director or officer of, or has a material interest in, any person who is a party to a material contract or proposed material contract with the corporation (an "Interested Director"), must disclose in writing to the corporation or request to have entered in the minutes of meetings of directors the nature and extent of his or her interest. A director referred to above must refrain from voting on any resolution to approve the contract, subject to certain conditions. Where a director or officer of a corporation fails to disclose his or her interest in a material contract in accordance with the provisions of the CBCA, a court may, on application of the corporation or a shareholder of the corporation, set aside the contract on such terms as it thinks fit. The Company's Articles and By-Laws are consistent with these provisions of the CBCA.

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Diretors' power, in the absence of an independent quorum, to vote compensation to themselves or any members of their body

Under the CBCA, an Interested Director may vote on any resolution to approve a contract if it is one relating primarily to his or her remuneration as a director, officer, employee or agent of the corporation or an affiliate. The Company's Articles and By-Laws are consistent with these provisions of the CBCA.

Borrowing powers of Directors

The Company's By-Laws expressly authorize, without in any way limiting the borrowing powers of the Company or of the directors as set out in the CBCA, to, from time to time, borrow money or otherwise obtain credit upon the credit of the Company in such amounts and upon such terms as may be considered advisable. Unless the Articles or By-Laws of the Company or a unanimous shareholder agreement provide otherwise, the directors may delegate to one or more of the officers and directors of the Company, all or any of the borrowing powers conferred on the directors of the Company pursuant to the Company's By-Laws in such manner as the directors shall determine at the time of each delegation.

Retirement of Directors pursuant to an age limit requirement

Neither the CBCA nor the Company's Articles or By-Laws provide for mandatory retirement of directors upon reaching a certain age.

Number of shares required for a Director's qualification

The Company's Articles and By-Laws do not require a director to hold a minimum number of shares in order to qualify as a director.

Rights, preferences and restrictions attaching to each class of shares:

(a) Dividend rights, including time limit after which dividend entitlement lapses

The holders of Common Shares of the Company are entitled to receive dividends as and when declared by the Board of Directors of the Company on the Common Shares as a class, subject to prior satisfaction of all preferential rights to dividends attached to all shares of other classes of shares of the Company ranking in priority to the Common Shares in respect of dividends.

The holders of each series of preferred shares ("Preferred Shares") of the Company are entitled, in priority to holders of Common Shares and any other shares of the Company ranking junior to the Preferred Shares from time to time with respect to the payment of dividends, to be paid rateably with holders of each other series of Preferred Shares, the amount of accumulated dividends, if any, specified as being payable preferentially to the holders of such series.

(b) Voting rights; staggered re-election intervals; cumulative voting

Each Common Share in the capital of the Company entitles its holder to one vote at any meeting of the Company's shareholders. The Company has no provision for staggered re-election intervals for its directors. Shareholders of the Company do not have cumulative voting.

(c) Rights to share in the Company's profits

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The right of shareholders to share in the profits of the Company is limited to their right to receive dividends if and when declared by the directors of the Company.

(d) Right to share in surplus in event of liquidation

The holders of Common Shares are entitled in the event of any liquidation, dissolution or winding-up of the Company, whether voluntary or involuntary, or any other distribution of the assets of the Company among its shareholders for the purpose of winding-up its affairs, and subject to prior satisfaction of all preferential rights to return of capital on dissolution attached to all shares of other classes of shares of the Company ranking in priority to the Common Shares in respect of return of capital on dissolution, to share rateably, together with the holders of shares of any other class of shares of the Company ranking equally with the Common Shares in respect of return of capital, in such assets of the Company as are available for distribution.

In the event of a distribution, holders of each series of Preferred Shares shall be entitled, in priority to holders of Common Shares and any other shares of the Company ranking junior to the Preferred Shares from time to time with respect to payment on a distribution, to be paid rateably with holders of each series of Preferred Shares the amount, if any, specified as being payable preferentially to the holders of such series on a distribution.

(e) Redemption provisions

No redemption rights attach to any of the shares of the Company.

(f) Sinking fund provisions

No sinking fund provisions attach to any of the shares of the Company.

(g) Liability to further capital calls by the Company

Shareholders are not liable to any capital calls by the Company.

(h) Other

There are no provisions discriminating against any existing or prospective shareholder of the Company as a result of such shareholder owning a substantial number of shares.

Actions necessary to change the rights of shareholders

In order to change the rights attaching to any class of shares of the Company, a resolution of the shareholders of each class of shares affected by such change must be passed by a majority of not less than two-thirds of the votes cast.

Shareholder Meetings

Under the CBCA, the directors of a corporation are required to call shareholders' meetings not later than fifteen (15) months after holding the last preceding annual meeting but no later than six months after the end of the corporation's preceding financial year. In addition, the holders of not less than5per cent of the issued shares of a corporation that carry the right to vote at a meeting sought to be held may requisition the directors to call a meeting of shareholders for the purposes stated in the requisition. Upon meeting the technical requirements set out in the CBCA for making such a requisition, the directors of the corporation must call a meeting of shareholders, subject to certain conditions. If they do not call a meeting of shareholders within twenty-one (21) days after receiving the requisition, any shareholder who signed the requisition may call the meeting. The directors of a corporation may at any time call a special meeting of shareholders.

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The Company's By-Laws provide that a quorum for the transaction of business at any meeting of its shareholders is two (2) persons present and holding or representing not less than 5% of the shares entitled to be voted at the meeting.

The Company's By-Laws provide that notice of the time and place of each meeting of shareholders shall be sent not less than twenty-one (21) days and not more than fifty (50) days before the meeting to each shareholder entitled to vote at the meeting, each director and the auditor of the Company. Such notice may be sent by mail addressed to, or may be delivered personally to, the shareholder, at his latest address as shown in the records of the Company or its transfer agent; to the director, at his latest address as shown in the records of the Company or in the last notice filed pursuant to section 106 or 113 of the CBCA; and to the auditor, at his most recent address as shown in the records of the Company. A notice of meeting of shareholders sent by mail to a shareholder, director or auditor in accordance with the above is deemed to be sent on the day on which it was deposited in the mail. A notice of a meeting is not required to be sent to shareholders who are not registered on the records of the Company or its transfer agent on the record date. Notice of a meeting of shareholders at which special business is to be transacted shall state the nature of such business in sufficient detail to permit the shareholder to form a reasoned judgment thereon and shall state the text of any special resolution to be submitted to the meeting.

Limitations on rights to own securities of the Company

TheInvestment Canada Act (the "ICA"), enacted on June 20, 1985,requires prior notification to the Government of Canada on the "acquisition of control" of Canadian businesses by non-Canadians, as defined in the ICA. The term "acquisition of control" is defined as any one or more non-Canadian persons acquiring all or substantially all of the assets used in the Canadian business, or the acquisition of the voting shares of a Canadian corporation carrying ona Canadian business or the acquisition of the voting interests of an entity controlling or carrying on a Canadian business. The acquisition of the majority of the outstanding shares is deemed to be an "acquisition of control" of a corporation. The acquisition of less than a majority, but one-third or more, of the voting shares of a corporation is presumed to be an "acquisition of control" of a corporation unless it can be established that the purchaser will not control the corporation.

Investments requiring notification and review by the Government of Canada are all direct acquisitions of Canadian businesses with assets of Cdn. $5,000,000 or more (subject to the comments below on WTO investors), and all indirect acquisitions of Canadian businesses (subject to the comments below on WTO investors) with assets of more than Cdn. $50,000,000 or with assets of between Cdn. $5,000,000 and Cdn. $50,000,000 which represent more than50%of the value of the total international transaction. In addition, specific acquisitions or new business in designated types of business activities related to Canada's cultural heritage or national identity could be reviewed if the Government of Canada considers that it is in the public interest to do so.

The ICA was amended with the implementation of the Agreement establishing the World Trade Organization ("WTO") to provide for special review thresholds for "WTO investors", as defined in the ICA. "WTO investor" generally means:

(a) an individual, other than a Canadian, who is a national of a WTO member (such as, for example, the United States), or who has the right of permanent residence in relation to that WTO member;

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(b) governments of WTO members; and

(c) entities that are not Canadian controlled, but which are WTO investor controlled, as determined by rules specified in the ICA.

The special review thresholds for WTO investors do not apply, and the general rules described above do apply, to the acquisition of control of certain types of businesses specified in the ICA, including a business that is a "cultural business". If the WTO investor rules apply, an investment in the shares of the Company by or from a WTO investor will be reviewable only if it is an investment to acquire control of the Company and the value of the assets of the Company is equal to or greater than a specified amount (the "WTO Review Threshold"). The WTO Review Threshold is adjusted annually by a formula relating to increases in the nominal gross domestic product of Canada. The 2001 WTO Review Threshold was Cdn. $209,000,000.

If any non-Canadian, whether or not a WTO investor, acquires control of the Company by the acquisition of shares, but the transaction is not reviewable as described above, the non-Canadian is required to notify the Canadian government and to provide certain basic information relating to the investment. A non-Canadian, whether or not a WTO investor, is also required to provide a notice to the government on the establishment of a new Canadian business. If the business of the Company is then a prescribed type of business activity related to Canada's cultural heritage or national identity, and if the Canadian government considers it to be in the public interest to do so, then the Canadian government may give a notice in writing within 21 days requiring the investment to be reviewed.

For non-Canadians (other than WTO investors), an indirect acquisition of control, by the acquisition of voting interests of an entity that directly or indirectly controls the Company, is reviewable if the value of the assets of the Company is then Cdn. $50,000,000 or more. If the WTO investor rules apply, then this requirement does not apply to a WTO investor, or to a person acquiring the entity from a WTO investor. Special rules specified in the ICA apply if the value of the assets of the Company is more than50%of the value of the entity so acquired. By these special rules, if the non-Canadian (whether or not a WTO investor) is acquiring control of an entity that directly or indirectly controls the Company, and the value of the assets of the Company and all other entities carrying on business in Canada, calculated in the manner provided in the ICA and the regulations under the ICA, is more than 50% of the value, calculated in the manner provided in the ICA and the regulations under the ICA, of the assets of all entities, the control of which is acquired, directly or indirectly, in the transaction of which the acquisition of control of the Company forms a part, then the thresholds for a direct acquisition of control as discussed above will apply, that is, a WTO Regulatory Threshold of Cdn. $209,000,000 (in 2000) for a WTO investor or threshold of Cdn. $5,000,000 for a non-Canadian other than a WTO investor. If the value exceeds that level, then the transaction must be reviewed in the same manner as a direct acquisition of control by the purchase of shares of the Company.

If an investor is reviewable, an application for review in the form prescribed by the regulations is normally required to be filed with the Director appointed under the ICA (the "Director") prior to the investment taking place and the investment may not be consummated until the review has been completed. There are, however, certain exceptions. Applications concerning indirect acquisitions may be filed up to 30 days after the investment is consummated and applications concerning reviewable investments in culture-sensitive sectors are required upon receipt of a notice for review. In addition, the Minister (a person designated as such under the ICA) may permit an investment to be consummated prior to completion of the review, if he is satisfied that delay would cause undue hardship to the acquiror or jeopardize the operations of the Canadian business that is being acquired. The Director will submit the application to the Minister, together with any other information or written undertakings given by the acquiror and any representation submitted to the Director by a province that is likely to be significantly affected by the investment.

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The Minister will then determine whether the investment is likely to be of net benefit to Canada, taking into account the information provided and having regard to certain factors of assessment where they are relevant. Some of the factors to be considered are:

(a) the effect of the investment on the level and nature of economic activity in Canada, including the effect on employment, on resource processing, and on the utilization of parts, components and services produced in Canada;

(b) the effect of the investment on exports from Canada;

(c) the degree and significance of participation by Canadians in the Canadian business and in any industry in Canada of which it forms a part;

(d) the effect of the investment on productivity, industrial efficiency, technological development, product innovation and product variety in Canada;

(e) the effect of the investment on competition within any industry or industries in Canada;

(f) the compatibility of the investment with national industrial, economical and cultural policies;

(g) the compatibility of the investment with national industrial, economic and cultural policies taking into consideration industrial, economic and cultural objectives enunciated by the government or legislature of any province likely to be significantly affected by the investment; and

(h) the contribution of the investment to Canada's ability to compete in world markets.

To ensure prompt review, the ICA sets certain time limits for the Director and the Minister. Within 45 days after a completed application has been received, the Minister must notify the acquiror that he is satisfied that the investment is likely to be of net benefit to Canada, or that he is unable to complete his review, in which case he shall have 30 additional days to complete his review (unless the acquiror agrees to a longer period), or he is not satisfied that the investment is likely to be of net benefit to Canada.

Where the Minister has advised the acquiror that he is not satisfied that the investment is likely to be of net benefit to Canada, the acquiror has the right to make representations and submit undertakings within 30 days of the date of the notice (or any other further period that is agreed upon between the acquiror and the Minister). On the expiration of the 30-day period (or the agreed extension), the Minister must quickly notify the acquiror that he is now satisfied that the investment is likely to be of net benefit to Canada or that he is not satisfied that the investment is likely to be of net benefit to Canada. In the latter case, the acquiror may not proceed with the investment or, if the investment has already been consummated, must divest itself of control of the Canadian business.

The ICA provides civil remedies for non-compliance with any provision. There are also criminal penalties for breach of confidentiality or providing false information.

Except as provided in the ICA, there are no limitations under the laws of Canada or in any constituent documents of the Company on the right of non-Canadians to hold or vote the Common Shares of the Company.

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Change of Control

There are no provisions of the Company's Articles or By-Laws that would have the effect of delaying, deferring or preventing a change in control of the Company and that would operate only with respect to a merger, acquisition or corporate restructuring involving the Company or any of its subsidiaries.

Share Ownership Disclosure

The Company's Articles or By-Laws do not contain any provision governing the ownership threshold above which shareholder ownership must be disclosed.

Changes in Capital

The Company's Articles or By-Laws do not impose conditions to changing its capital that are more stringent than those required by the CBCA.

C. Material Contracts

The Company is not party to any material contracts other than contracts entered into in the ordinary course of business.

D. Exchange Controls

Canada has no system of exchange controls. There are no exchange restrictions on borrowing from foreign countries nor on the remittance of dividends, interest, royalties and similar payments, management fees, loan repayments, settlement of trade debts or the repatriation of capital.

E. Taxation

Canadian Federal Income Tax Considerations

The following is a summary of the principal Canadian federal income tax considerations generally applicable in respect of the Common Shares. The tax consequences to any particular holder of Common Shares will vary according to the status of that holder as an individual, trust, corporation, or member of a partnership, the jurisdiction in which that holder is subject to taxation, the place where that holder is resident and, generally, according to that holder's particular circumstances. This summary is applicable only to holders who are resident in the United States, have never been resident in Canada, hold their Common Shares as capital property and will not use or hold the Common Shares in carrying on business in Canada.

Generally, dividends paid by Canadian corporations to non-resident shareholders are subject to a withholding tax of 25% of the gross amount of such dividends. However, Article X of the reciprocal tax treaty between Canada and the United States reduces to 15% the withholding taxon the gross amount of dividends paid to residents of the United States. The withholding tax rate on the gross amount of dividends is reduced to5%if the beneficial owner of the dividend is a U.S. corporation which owns at least 10% of the voting stock of the Canadian corporation paying the dividends.

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A non-resident who holds shares of the Company as capital property will not be subject to tax on capital gains realized on the disposition of such shares unless such shares are "taxable Canadian property" within the meaning of theIncome Tax Act (Canada) and no relief is afforded under any applicable tax treaty. The shares of the Company would be taxable Canadian property of a non-resident if at any time during the five year period immediately preceding a disposition by the non-resident of such shares not less than 25% of the issued shares of any class of the Company belonged to the non-resident, persons with whom the non-resident did not deal at arm's length, or to the non-resident and persons with whom the non-resident did not deal at arm's length.

Certain U.S. Federal Income Tax Considerations

The following summary describes certain U.S. federal income tax consequences that may be relevant to the ownership and disposition of Common Shares by U.S. Holders (as defined below) who purchase such shares in this offering. Except where noted, this summary deals only with Common Shares held as capital assets as defined in 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 and traders in securities or currencies, financial institutions, insurance companies, tax-exempt organizations, persons holding Common Shares as a part of a straddle, hedge, or conversion transaction or a synthetic security or other integrated transaction, regulated investment companies, traders in securities who elect to mark-to-market their securities, persons actually or constructively own or have owned 10% or more of our voting stock, persons who acquired their Common Shares through the exercise or cancellation of employee stock options or otherwise as compensation for services, U.S. expatriates, persons subject to the alternative minimum tax, U.S. Holders whose “functional currency” is not the U.S. dollar, and holders who are not U.S. Holders. This discussion does not cover any state, local, or foreign tax consequences or United States federal tax consequences (e.g., estate or gift tax) other than those pertaining to income tax. The discussion is based upon the provisions of the Code and United States Treasury regulations, rulings and judicial decisions under the Code, all as currently in effect as of the date of this prospectus supplement, and those authorities may be repealed, revoked or modified (possibly with retroactive effect) so as to result in U.S. federal income tax consequences different from those discussed below. There can be no assurance that the Internal Revenue Service (the “IRS”) will take a similar view as to any of the tax consequences described in this summary.

THE FOLLOWING DISCUSSION IS FOR GENERAL INFORMATION ONLY AND IS NOT INTENDED TO BE, NOR SHOULD IT BE CONSTRUED TO BE, LEGAL OR TAX ADVICE TO ANY HOLDER OR PROSPECTIVE HOLDER OF COMMON SHARES OF THE COMPANY AND NO OPINION OR REPRESENTATION WITH RESPECT TO THE U.S. FEDERAL INCOME TAX CONSEQUENCES TO ANY HOLDER OR PROSPECTIVE HOLDER IS MADE. U.S. HOLDERS AND PERSONS CONSIDERING THE PURCHASE, OWNERSHIP OR DISPOSITION OF COMMON SHARES SHOULD CONSULT THEIR OWN TAX ADVISORS CONCERNING THE U.S. FEDERAL INCOME OR OTHER TAX CONSEQUENCES IN LIGHT OF THEIR PARTICULAR SITUATIONS AS WELL AS ANY CONSEQUENCES ARISING UNDER THE LAWS OF ANY STATE OR OF ANY LOCAL OR FOREIGN TAXING JURISDICTION.

As used in this section, a “U.S. Holder” of Common Shares means a holder that is (i) a citizen or individual resident of the United States for U.S. federal income tax purposes, (ii) a corporation, or other entity taxable as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States or any political subdivision thereof or therein, (iii) an estate, the income of which is subject to U.S. federal income taxation regardless of its source, or (iv) a trust (A) which is subject to the supervision of a court within the United States and the control of a United States person, or

53

(B) that was in existence on August 20, 1996, was treated as a United States person under the Code on the previous day, and validly elected to continue to be so treated under applicable United States Treasury regulations. If a partnership or other flow-through entity holds Common Shares, the U.S. 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 U.S. Holder that is a partner of the partnership or an owner of another flow-through entity holding Common Shares should consult its own tax advisors.

Payment of Dividends

Unless we are treated as a passive foreign investment company, described below, the gross amount of distributions paid to a U.S. Holder of Common Shares (including amounts withheld to pay Canadian withholding taxes as described below) will be treated as dividend income to such U.S. Holder, to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. Such income will be includable in the gross income of a U.S. Holder on the day received by the U.S. Holder. In the case of a taxable corporate U.S. Holder, such dividends will be taxable as ordinary income and will not be eligible for the corporate dividends received deduction, which is generally allowed to U.S. corporate shareholders on dividends received from a domestic corporation. Provided that we are not treated as a passive foreign investment company, described below, a foreign personal holding company (for 2004 and earlier years) or a foreign investment company, in the case of an individual U.S. Holder, such dividends may be eligible for a maximum tax rate of 15% for dividends received before January 1, 2009, provided such holder holds the Common Shares for at least 60 days and certain other conditions are satisfied.

To the extent that the amount of any distribution exceeds our current and accumulated earnings and profits for a taxable year, the distribution will first be treated as a tax-free return of capital, causing a reduction in the adjusted tax basis of the Common Shares (thereby increasing the amount of gain, or decreasing the amount of loss, to be recognized by the U.S. Holder on a subsequent disposition of the Common Shares) and any excess will be treated as capital gain. Such distributions generally will not give rise to foreign source income for foreign tax credit purposes. We do not currently maintain calculations of our earnings and profits for U.S. federal income tax purposes.

The amount of any distribution paid in Canadian dollars will equal the U.S. dollar value of the Canadian dollars received calculated by reference to the exchange rate in effect on the date the dividend is received by the U.S. Holder regardless of whether the Canadian dollars are converted into U.S. dollars. If the Canadian dollars received as a distribution are not converted into U.S. dollars on the date of receipt, a U.S. Holder will have a basis in the Canadian dollars equal to its U.S. dollar value on the date of receipt. Any U.S. holder who receives payment in Canadian dollars and engages in a subsequent conversion or other disposition of the Canadian dollars may have a foreign currency exchange gain or loss that would be treated as ordinary income or loss, and generally will be U.S. source income or loss for foreign tax credit purposes. U.S. Holders are urged to consult their own tax advisors concerning the U.S. tax consequences of acquiring, holding and disposing of Canadian dollars.

Foreign Tax Credit

A U.S. Holder may be entitled to deduct, or claim a foreign tax credit for such Canadian taxes, subject to applicable limitations in the Code. Dividends will be income from sources outside the United States, and for taxable years beginning before January 1, 2007, generally will be “passive income” or “financial services income” for purposes of computing the foreign tax credit allowable to a

54

U.S. Holder. For taxable years beginning after December 31, 2006, dividends generally will be "passive category income" or "general category income" for purposes of computing the foreign tax credit allowable to a U.S. Holder. The rules governing the foreign tax credit are complex, and additional limitations on the credit apply to individuals receiving dividends from foreign corporations if the dividends are eligible for the 15% maximum tax rate on dividends described above. Investors are urged to consult their tax advisors regarding the availability of the foreign tax credit under their particular circumstances.

Sale or Exchange of Common Shares

For U.S. federal income tax purposes, a U.S. Holder generally will recognize a taxable gain or loss on any sale or exchange of a Common Share in an amount equal to the difference (if any) between the U.S. dollar value of the amount realized for the Common Share and the U.S. Holder’s adjusted tax basis (determined in U.S. dollars) in the Common Share. Unless we are treated as a passive foreign investment company, described below, such gain or loss will be a capital gain or loss. Capital gains of non-corporate taxpayers, including individuals, derived with respect to a sale, exchange or other disposition prior to January 1, 2009 of Common Shares held for more than one year are subject to a maximum federal income tax rate of 15%. The deductibility of capital losses is subject to limitations. Any gain or loss recognized by a U.S. Holder will generally be treated as U.S. source gain or loss for foreign tax credit limitation purposes.

Passive Foreign Investment Company Rules

The United States federal income tax consequences for a U.S. Holder of owning our shares will depend to a significant extent on whether Luke Energy Ltd. is a passive foreign investment company at any time during the U.S. Holder’s holding period.

Determining Passive Foreign Investment Company Status

For United States federal income tax purposes, a foreign corporation is generally classified as a passive foreign investment company for each taxable year in which either:

• at least 75% of its gross income is “passive” income (referred to as the “income test”), or

• at least 50% of the average value of its assets is attributable to assets that produce passive income or are held for the production of passive income (referred to as the “asset test”).

For purposes of the income test and the asset test, if a foreign corporation owns directly or indirectly at least 25% (by value) of the stock of another corporation, that foreign corporation will be treated as if it held its proportionate share of the assets of the other corporation and received directly its proportionate share of the income of that other corporation. Also, for purposes of the income test and the asset test, passive income does not include any income that is interest, a dividend or a rent or royalty, which is received or accrued from a related person to the extent that amount is properly allocable to the income of the related person that is not passive income. For these purposes, a person is “related” with respect to a foreign corporation if that person controls the foreign corporation or is controlled by the foreign corporation or by the same persons that control the foreign corporation. For these purposes, “control” means ownership, directly or indirectly, of stock possessing more than 50% of the total voting power of all classes of stock entitled to vote or of the total value of stock of a corporation.

Passive income also includes the excess of gains over losses from some commodities transactions, including some transactions involving oil and gas. For 2004 and earlier years, gains from commodities transactions are generally excluded from the definition of passive income if “substantially all” of a merchant’s or producer’s or handler’s business is as an active merchant, producer or handler of those commodities. Applicable Treasury regulations interpret “substantially all” to mean that 85% or

55

more of a producer’s taxable income must be gross receipts from sales in the active conduct of a commodities business or certain related activities. For 2005 and later years, net gains from commodities transactions will not be included in the definition of passive income if they are active business gains or losses from the sale of commodities, but only if substantially all of a corporation’s commodities are: stock in trade or inventory, depreciable or real property used in trade or business, or supplies used in the ordinary course of the trade or business of a corporation. Net gains from commodities transactions will also not be included in the definition of passive income if they arise out of commodity hedging transactions entered into in the ordinary course of a corporation’s trade or business.

The passive foreign investment company rules contain an exception for companies in their “start-up year”. A corporation will not be treated as a passive foreign investment company for the first taxable year the corporation has gross income, if (i) no predecessor of such corporation was a passive foreign investment company, (ii) the corporation establishes that it will not be a passive foreign investment company for either of the 1st 2 taxable years following the start-up year and (iii) the corporation is in fact not a passive foreign investment company for either of the 1st 2 taxable years following the start-up year. Under these rules and definitions, we believe that we were not a passive foreign investment company in 2003 due to the start-up year exception. For 2004, the first taxable year following the start-up year, we were not a passive foreign investment company under either the income test or the asset test. We believe we will not be a passive foreign investment company in 2005 or subsequent years. We note, however, that passive foreign investment company status is fundamentally factual in nature, generally cannot be determined until the close of the taxable year in question and is determined annually. Consequently, we can provide no assurance that we will not be a passive foreign investment company for either the current taxable year or for any subsequent taxable year, and if Luke Energy is a passive foreign investment company in 2005, then it will not qualify for the start-up exception and will be a passive foreign investment company for 2003 and may be treated as a passive foreign investment company in later years with respect to shareholders whose holding periods began in 2003. U.S. Holders are urged to consult their own tax advisors regarding our possible classification as a passive foreign investment company and the consequences if that classification were to occur.

Other Rules

Certain special rules, such as the foreign personal holding company rules (repealed for taxable years after 2004), the foreign investment company rules and the controlled foreign corporation rules apply under certain circumstances to stock of a non-US issuer. We believe that none of these rules currently apply to our Common Shares; however, this conclusion is a factual determination made annually and thus may be subject to change based on future changes in the ownership of our stock and our operations. If either of these rules apply, the tax consequences would be materially different than those described above.

Backup Withholding and Information Reporting

In general, information reporting requirements will apply to dividends paid on and proceeds received on the sale, exchange or redemption of the Common Shares that are paid within the United States or through some U.S. related financial intermediaries to U.S. Holders, and backup withholding tax, currently at a 28% rate, may apply to such amounts unless the U.S. Holder is an exempt recipient (such as a corporation) or provides a taxpayer identification number and certifies that no loss of exemption from backup withholding has occurred. In addition, a backup withholding tax may apply if such a U.S. Holder fails to provide an accurate taxpayer identification number or otherwise fails to comply with applicable requirements of the backup withholding rules. Any amounts withheld under those rules will be allowed as a credit against the U.S. Holder's U.S. federal income tax liability and may entitle the U.S. Holder to a refund to the extent it exceeds such liability. A U.S. Holder who does not provide a correct taxpayer identification number may be subject to penalties imposed by the IRS.

56

F. Dividends and Paying Agents

Not Applicable.

G. Statement by Experts

Not Applicable.

H. Documents on Display

Copies of all documents referred to herein are available for inspection in the Company's offices at 1200, 520 - 5^th Avenue S.W., Calgary, Alberta, T2P 3R7.

The Company is also required to file reports and other information with certain securities commissions in Canada. These reports, statements and other information are available electronically from the Canadian System for Electronic Document Analysis and Retrieval (SEDAR) (http://www.sedar.com), the Canadian equivalent of the SEC's electronic document gathering and retrieval system (EDGAR).

I. Subsidiary Information

Not Applicable.

ITEM 11 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

At December 31, 2004 the Company had no derivative financial instruments or long term debt. The Company is exposed to fluctuations in oil and natural gas prices and foreign currency exchange rates. Discussion of these risks is set forth in Item 3.D under the heading "Risk Factors".¹

ITEM 12 DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not Applicable.

PART II

ITEM 13 DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES

There has not been a material default in the payment of principal, interest, a sinking or purchase fund instalment, or any other material default not cured within thirty days, relating to indebtedness of the Company or any of its subsidiaries. There are no payments of dividends by the Company in arrears, nor has there been any other material delinquency relating to any class of preference shares of the Company.

ITEM 14 MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS

Neither the Company nor any other person has (i) modified materially any instrument defining the rights of holders of any class of registered securities of the Company, or (ii) modified materially or qualified the rights evidenced by any class of registered securities of the Company by issuing or modifying any other class of securities.

57

ITEM 15 CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

The Company’s Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of Luke's disclosure controls and procedures as of December 31, 2004. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of 2004, the Company’s disclosure controls and procedures were effective to ensure that information the Company is required to disclose in its filings under the Exchange Act are recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms, and to ensure that information required to be disclosed by it in the reports that the Company files under the Exchange Act is accumulated and communicated to management, including the Company’s principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Changes to Internal Controls and Procedures for Financial Reporting.

Since the Company’s formation on January 9, 2003, the Company has developed and established its internal controls and procedures for financial reporting. Subsequent to the establishment of such procedures and controls, there have were no significant changes during the period covered by this annual report to such internal controls over financial reporting or in other factors that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting.

ITEM 16 OTHER

A. Audit Committee Financial Expert

The Company's Board of Directors has determined that Ronald L. Belsher, CA, an independent director (as defined in the Toronto Stock Exchange Company Manual) serving on the Company's audit committee, is a financial expert.

B. Code of Ethics

The Company's Board of Directors has adopted a Code of Ethics (the "Code") that is applicable to all senior officers of the Company, and compliance with which is a condition of their employment. The following is a summary of same:

Conflicts of Interest

All senior officers must avoid any personal activity, investment or association that could appear to interfere with their judgment concerning the Company’s best interests. An officer may not take advantage of his or her position or relationship with the Company for personal gain and should avoid even the appearance of a conflict of interest. Engaging in any conduct that represents a conflict of interest is prohibited under the Code.

58

Accurate Periodic Reports

All senior officers are required to exercise the highest standard of care in preparing reports and documents that are filed with regulatory authorities or otherwise disseminated to the public, and such reports shall be prepared in accordance with all applicable laws. Further thereto:

• all accounting records, and the reports produced from such records, must be in accordance with all applicable laws;

• all accounting records must fairly and accurately reflect the transactions or occurrences to which they relate;

• all accounting records must fairly and accurately reflect in reasonable detail the Company’s assets, liabilities, revenues and expenses;

• no accounting records should contain any false or intentionally misleading entries;

• no transactions should be intentionally misclassified as to accounts, departments or accounting periods;

• all transactions must be supported by accurate documentation in reasonable detail and recorded in the proper account and in the proper accounting period;

• no information should be concealed from the internal auditors or the independent auditors; and

• compliance with the Company’s system of internal controls is required.

Compliance with Laws

Management of the Company is expected to comply with both the letter and spirit of all applicable laws and governmental rules and regulations.

Compliance with this Code

Failure to comply with the Code or applicable laws, rules or regulations (including without limitation all rules and regulations of applicable securities commissions) will subject a member of management to disciplinary measures, up to and including discharge from the Company.

The Board of Directors will determine, or designate appropriate persons to determine, appropriate actions to be taken in the event of a violation of the Code. In determining what action is appropriate in a particular case, the Board or its designee will consider the nature and severity of the violation, whether the violation was a single occurrence or repeated occurrences, whether the violation was intentional or inadvertent, whether the individual in question had been advised prior to the violation as to the proper course of action and whether or not the individual in question had committed other violations in the past.

In addition to the foregoing, members of management are expected to report all violations of the Code promptly to the Chairman of the Audit Committee.

59

C. Principal Accountant Fees and Services

		2004		2003
• Audit Fees	$	50,000	$	15,000
• Audit Related Fees(1)	$	10,000	$	9,000
• Tax Fees(2)	$	10,000	$	6,200
• All Other Fees(3)	$	10,000	$	6,000
TOTAL	$	80,000	$	36,200

Notes:

(1) These services were for the review of the Company's interim financial statements.

(2) These fees were for the review of the corporate tax return and assistance with tax compliance matters.

(3) These fees were primarily for attendances at due diligence meetings related to financings of the Company.

(4) All audit, audit-related and tax services and fees were pre-approved by the Audit Committee.

Pre-Approval of Policies and Procedures

Luke has adopted polices and procedures with respect to the pre-approval of audit and permitted non-audit services to be provided by KPMG LLP as set forth in the Audit Committee Charter (see Item 6.C). The Audit Committee has approved the provision of a specified list of audit and permitted non-audit services that the audit committee believes to be typical, re-occurring or otherwise likely to be provided by KPMG LLP during the current fiscal year. The list of services is sufficiently detailed as to the particular services to be provided to ensure that the audit committee knows precisely what services it is being asked to pre-approve and it is not necessary for any member of management to make a judgment as to whether a proposed service fits within pre-approved services.

D. Exemptions from the Listing Standards for Audit Committees

Not applicable.

E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The Company and its affiliates have not purchased any equity securities

ITEM 17 FINANCIAL STATEMENTS

The following financial statements are attached and incorporated herein:

•	Auditors' Report dated March 8, 2005	F-1
•	Balance Sheets as at December 31, 2004 and December 31, 2003.	F-2
•	Statements of Earnings and Retained Earnings for the Year Ended December 31, 2004 and the Period Ended December 31, 2003.	F-3
•	Statements of Cash Flow for the Year Ended December 31, 2004 and the Period Ended December 31, 2003.	F-4
•	Notes to Financial Statements for the Periods Ended December 31, 2004 and December 31, 2003.	F-5
•	Statements of revenue and operating expenses of the Retained Assets to be transferred to the Company for the three-year period ended December 31, 2002.	F-18
•	Unaudited pro forma statements of earnings for the years ended December 31, 2003 and 2002	F-22

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ITEM 18 FINANCIAL STATEMENTS

See Item 17.

ITEM 19 EXHIBITS

The following exhibits are attached and incorporated by reference herein:

1.1 Certificate of Incorporation*

1.2 Articles of Incorporation*

1.3 By-Laws of the Registrant*

12.1 Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

12.2 Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

13.1 Certification of the Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

13.2 Certification of the Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

*Previously filed.

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SIGNATURE

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	LUKE ENERGY LTD.
	Registrant
	By:/s/Harold V. Pedersen
	Name: Harold V. Pedersen
	Title: President & CEO
Date: April 30, 2005

62

Financial Statements of

LUKE ENERGY LTD.

Year ended December 31, 2004 and Period Ended December 31, 2003

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Luke Energy Ltd.

We have audited the balance sheets of Luke Energy Ltd. as at December 31, 2004 and 2003 and the statements of earnings and retained earnings and cash flows for the year ended December 31, 2004 and the period from January 9, 2003 to December 31, 2003. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those 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.

In our opinion, these 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 its cash flows for the year ended December 31, 2004 and the period from January 9, 2003 to December 31, 2003 in accordance with Canadian generally accepted accounting principles.

Canadian generally accepted accounting principals vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences is presented in note 13 of the financial statements.

KPMG LLP

Chartered Accountants

Calgary, Canada

March 8, 2005

F-1

LUKE ENERGY LTD.

BALANCE SHEETS

		December 31, 2004		December 31, 2003
				(restated1)
Assets
Current assets:
	Cash and cash equivalents	$	21,893,603	$	36,699,571
	Accounts receivable		2,697,334		529,815
			24,590,937		37,229,386
Capital assets (note 4)			34,856,766		7,998,257
		$	59,447,703	$	45,227,643
Liabilities and Shareholders’ Equity
Current liabilities:
	Accounts payable and accrued liabilities	$	7,382,282	$	2,203,148
Asset retirement obligations (note 6)			509,330		110,930
Future taxes (note 9)			1,055,250		98,850
Shareholders’ equity:
	Share capital (note 7)		48,130,532		42,223,171
	Contributed surplus		900,033		221,710
	Retained earnings		1,470,276		369,834
			50,500,841		42,814,715
		$	59,447,703	$	45,227,643

¹ See note 3 to the financial statements

See accompanying notes to financial statements.

On behalf of the Board:

/s/ Harold V. Pedersen	/s/ Mary C. Blue
Director	Director
Harold V. Pedersen	Mary C. Blue

F-2

LUKE ENERGY LTD.

STATEMENTS OF EARNINGS AND RETAINED EARNINGS

	��	Year Ended			Period Ended
		December 31,			December 31,
		2004			2003
					(restated1)
Revenue:
	Oil and gas production	$	10,705,520		$	1,715,620
	Royalties, net of Alberta Royalty Tax Credit		(2,008,592	)		(434,687	)
			8,696,928			1,280,933
Other income:
	Interest		778,053			953,464
	Gain (loss) on sale of marketable securities		(295,235	)		629,575
			482,818			1,583,039
Expenses:
	Operating		1,991,048			262,754
	General and administrative		1,962,188			1,126,790
	Stock-based compensation		698,113			221,710
	Interest		-			2,680
	Depletion, depreciation and accretion		2,357,955			493,404
			7,009,304			2,107,338
Earnings before taxes			2,170,442			756,634
Taxes (note 9):
	Current		5,000			96,800
	Future		1,065,000			290,000
			1,070,000			386,800
Earnings		$	1,100,442		$	369,834
Retained earnings, beginning of period			369,834			-
Retained earnings, end of period			1,470,276			369,834
Weighted average number of common shares outstanding (note 8)			35,204,971			29,759,428
Earnings per share - basic and diluted		$	0.03		$	0.01

¹ See note 3 to the financial statements

See accompanying notes to financial statements.

F-3

LUKE ENERGY LTD.

STATEMENTS OF CASH FLOWS

			Year Ended			Period Ended
			December 31,			December 31,
			2004			2003
						(restated1)
Cash provided by (used in):
Operating:
	Earnings for the period		$	1,100,442		$	369,834
	Items not affecting cash:
		Depletion, depreciation and accretion		2,357,955			493,404
		Future taxes		1,065,000			290,000
		Stock-based compensation		698,113			221,710
				5,221,510			1,374,948
	Change in non-cash working capital (note 10)			(1,008,292	)		45,959
				4,213,218			1,420,907
Financing:
	Common shares issued, net of Issues costs (note 7)			5,735,721			38,486,155
	Stock options exercised			43,250			-
	Initial common shares redeemed for cash			-			(100	)
				5,778,971			38,486,055
Investing:
	Additions to capital assets			(28,818,064	)		(4,834,865	)
	Change in non-cash working capital (note 10)			4,019,907			1,627,374
				(24,798,157	)		(3,207,491	)
Increase (decrease) in cash				(14,805,968	)		36,699,471
Cash and cash equivalent, beginning of period				36,699,571			100
Cash and cash equivalent, end of period			$	21,893,603		$	36,699,571

¹ See note 3 to the financial statements

See accompanying notes to financial statements.

F-4

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

1.	INCORPORATION AND PLAN OF ARRANGEMENT:
	Luke Energy Ltd. (“Luke Energy” or the “Company”) is engaged in the acquisition, exploration, development and production of oil and gas reserves in western Canada.
	The Company was incorporated pursuant to the Canada Business Corporations Act on January 9, 2003 as a wholly-owned subsidiary of KeyWest Energy Corporation (“KeyWest”). Pursuant to a plan of arrangement between Viking Energy Royalty Trust, Viking Holdings Inc., Viking KeyWest Inc., KeyWest and Luke Energy, KeyWest transferred interests in certain petroleum and natural gas properties and related facilities (“Retained Assets”) to Luke Energy in exchange for common shares in Luke Energy. On February 26, 2003, the closing of the plan of arrangement, the common shares of Luke Energy held by KeyWest were distributed to the shareholders of KeyWest on a one for ten basis. Luke Energy began trading on the Toronto Stock Exchange on February 28, 2003.
	The following summarizes the transfer of the Retained Assets which were initially recorded at KeyWest’s net book value as Luke Energy and KeyWest were related parties. The amounts were then adjusted for the recording of asset retirement obligations and the future tax asset. The results of the operations of the Retained Assets were included from February 26, 2003.
	Net assets acquired and liabilities assumed:

Petroleum and natural gas rights	$	2,482,106
Equipment and facilities		1,126,009
Future tax asset		628,550
Asset retirement obligation		(62,250	)
	$	4,174,415
Consideration:
Issuance of 6,581,364 common shares	$	4,174,415

2.	SIGNIFICANT ACCOUNTING POLICIES:
	The financial statements of the Company have been prepared in accordance with generally accepted accounting principles in Canada. In all material respects, these accounting principles are generally accepted in the United States except as described in note 13.

F-5

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents includes highly liquid, short-term investments with a maturity of ninety days or less at the time of issue.

Capital Assets

The Company follows the full cost method of accounting for petroleum and natural gas operations, whereby all costs of exploring, developing and acquiring petroleum and natural gas properties, including asset retirement costs, are capitalized and accumulated in one cost centre. Costs include land acquisition costs, geological and geophysical charges, carrying charges on non-productive properties, costs of drilling both productive and non-productive wells, tangible production equipment and that portion of general and administrative expenses directly attributable to exploration and development activities. Gains and losses are not recognized upon disposition of petroleum and natural gas properties unless such a disposition would alter the rate of depletion by 20% or more.

Depletion and Depreciation

All costs of acquisition, exploration and development of oil and gas reserves, associated well equipment and facilities (net of salvage value), and estimated costs of future development of proven undeveloped reserves are depleted and depreciated by the unit-of-production method based on estimated proven reserves before royalties as determined by independent engineers. Natural gas reserves and production are converted to equivalent barrels of crude oil based on relative energy content of six Mcf of gas to one barrel of oil. Costs of unproved properties are initially excluded from depletion calculations. These unproved properties are assessed periodically to ascertain whether impairment has occurred. When proven reserves are assigned or the property is considered impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

Depreciation of office furniture and equipment is provided using the straight-line method based on estimated useful lives.

F-6

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

Ceiling Test

In applying the full cost method, the Company calculates a ceiling test whereby the carrying value of petroleum and natural gas properties is compared annually to the sum of the undiscounted cash flows expected to result from the Company’s proved reserves and the lower of cost and market of unproved properties. Cash flows are based on third party quoted forward prices, adjusted for the Company’s contracted prices and quality differentials. Should the ceiling test result in an excess of carrying value, the Company would then measure the amount of impairment by comparing the carrying amounts of petroleum and natural gas properties to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves and the lower of cost and market of unproved properties. The Company’s risk-free interest rate is used to arrive at the net present value of the future cash flows. The excess of the carrying value over future cash flows would be recorded as a permanent impairment.

Asset Retirement Obligations

The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred when a reasonable estimate of fair value can be made. The fair value is based on estimates of future costs, reserve life, inflation and discount rates. The provision is recorded as a long-term liability, with a corresponding increase in the carrying value of the associated asset. The capitalized amount is depleted on a unit-of-production basis based on estimated proven reserves before royalties as determined by independent engineers. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the asset retirement obligation. Actual asset retirement expenditures are charged against the liability to the extent of the liability recorded.

Joint Interest Operations

A portion of the Company’s exploration, development and production activities are conducted jointly with others. These financial statements reflect only the Company’s proportionate interest in such activities.

Flow-through Shares

The resource expenditure deductions related to exploratory activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. A future tax liability is recognized and share capital is reduced by the estimated tax cost of the renounced expenditures when the renunciation is made.

Stock-based Compensation Plans

The Company has a stock-based compensation plan as described in Note 7. The Company uses the fair value method of accounting for stock-based compensation whereby the Company recognizes the cost of stock options granted to employees, directors and certain consultants. The fair value of stock options is determined using the Black-Scholes option pricing model. Consideration paid by the option holder on exercise of stock options is recorded as share capital.

F-7

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

	Income Taxes
	The Company uses the liability method of tax allocation accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse.
	Foreign Currency Translation
	At year-end monetary assets and liabilities denominated in foreign currencies are translated into Canadian dollars at the year-end exchange rates. Gains or losses on translation are included in earnings.
	Use of Estimates
	The amounts recorded for depletion, depreciation and accretion of capital assets and the provision of future site restoration are based on estimates. The ceiling test is based on estimates of proved reserves, production rates, oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future periods could be significant.
	Per Share Amounts
	Basic earnings per common share are computed by dividing earnings by the weighted average number of common shares outstanding for the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares, including stock options, were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments.
3.	CHANGES IN ACCOUNTING POLICIES
	Stock-based Compensation:
	Pursuant to an amended accounting pronouncement for stock-based compensation, the Company changed its accounting policy on January 1, 2004 from the intrinsic method to the fair value method to account for options granted under the stock option plan. Application of the fair value method results in recognition of compensation expense in the statement of earnings with a corresponding amount recorded as contributed surplus. The new method was applied retroactively with restatement of the prior period financial statements. The change resulted in a reduction in earnings of $698,113 ($0.02 per share) for the year ended December 31, 2004 and $214,092 ($0.01 per share) for the period ended December 31, 2003.

F-8

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

	Flow-through Shares
	On March 16, 2004 the Emerging Issues Committee of the CICA clarified that estimated future tax costs of expenditures renounced to flow-through shareholders should be recorded when the expenditures are renounced. Prior to March 16, 2004 the Company recorded the estimated tax cost of the renounced expenditures on the date the shares were issued. As a result, the Company has not recorded an estimated tax cost for the flow-through share issued in 2004. Accordingly, the cost will be recorded in 2005 when the renunciation is made.
4.	CAPITAL ASSETS

	2004				2003
			Accumulated				Accumulated
			depletion and				depletion and
	Cost		depreciation		Cost		depreciation
Petroleum and natural gas properties, including well equipment	$	37,299,505	$	2,724,000	$	8,311,208	$	463,000
Office furniture and Equipment		390,750		109,489		175,983		25,934
	$	37,690,255	$	2,833,489	$	8,487,191	$	488,934
Net book value			$	34,856,766			$	7,998,257

At December 31, 2004, costs of $6.7 million (2003 - $2.8 million) related to unproven properties have been excluded from the depletion calculation. In addition, $3.3 million of costs (including $2.2 million of pipe and casing inventory) incurred for the 2005 Marten Creek drilling program were excluded from the depletion calculation. In 2004, the Company capitalized $548,037 (2003 - $188,475) of general and administrative expenses directly related to exploration and development activities.

Included in the Company’s petroleum and natural gas properties is $438,869 (2003 - $98,044), net of accumulated depletion, relating to the asset retirement obligation.

At December 31, 2004, flow-through share arrangements require the Company to incur approximately $5.5 million in exploratory costs prior to December 31, 2005.

F-9

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

The Company performed a ceiling test calculation at December 31, 2004 to assess the recoverable value of petroleum and natural gas properties. The present value of future net revenues from the Company’s proved plus probable reserves exceeded the carrying value of the Company’s petroleum and natural gas properties at December 31, 2004. The calculation was based on the year-end independent engineering evaluation (forecasted price case). The future pricing assumptions used in the engineering evaluation are as follows:

	Oil		Foreign		Natural Gas
	WTI Ref		Exchange		AECO Spot
Year	US $/bbl		Rate		Cdn $/MMbtu
2005	42.00		0.82		6.60
2006	40.00		0.82		6.35
2007		38.00		0.82		6.15
2008		36.00		0.82		6.00
2009		34.00		0.82		6.00
2010-12		33.00		0.82		6.00
2013-15		+1.5%/yr.		0.82		+1.5%/yr.
2016+		+2.0%/yr.		0.82		+2.0%/yr.

5.	CREDIT FACILITY
	The Company has an $11 million production loan facility available with a major Canadian bank. Pursuant to the terms of the agreement, any amounts owing will revolve until September 30, 2005 and for a further period of 364 days thereafter at the request of the Company and with the consent of the bank. During the revolving phase, the loan has no specific terms of repayment. The facility bears interest at the lender's prime lending rate or the Banker’s Acceptance rate plus a margin based on the ratio of debt to cash flow, currently set as nil and 1.25% respectively. A standby fee of 0.2% per annum is levied on the unused portion of the facility.
	Upon the expiration or termination of the revolving phase of the loan, any balance outstanding on the loan converts to a two-year term loan. The first repayment of one half of the outstanding balance is due on the 366th day after conversion followed by four quarterly repayments. During the term loan phase, interest rates will increase 0.5% from those during the revolving phase.
	The facility is secured by a first floating charge demand debenture over all of the Company’s assets.
	Subsequent to year-end the Company arranged for an increase in the production loan facility to $16 million.

F-10

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

6.	ASSET RETIREMENT OBLIGATIONS
	The total future asset retirement obligation was estimated by management based on the Company’s net ownership in wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At December 31, 2004 the net present value of the total asset retirement obligation is estimated to be $509,330 based on a total future liability of $809,000. These payments are expected to be made over the next 29 years with the majority of costs incurred between 2010 and 2023. The Company’s credit adjusted risk free rate of eight percent and an inflation rate of 1.5 per cent were used to calculate the present value of the asset retirement obligation.
	The following table reconciles the Company’s asset retirement obligations:

	2004		2003
Carrying amount, beginning of the period	$	110,930	$	-
Recorded on acquisition of properties (note 1)		-		62,250
Increase in liabilities, during the period		385,000		44,210
Accretion expense		13,400		4,470
Carrying amount, end of period	$	509,330	$	110,930

7.	SHARE CAPITAL
	The Company is authorized to issue an unlimited number of common shares together with an unlimited number of preferred shares issuable in series.
	Common Shares
	Common shares issued and outstanding:

	Number of Shares			Amount
Balance at January 9, 2003, date of incorporation		100		$	100
Initial shares redeemed for cash		(100	)		(100	)
Issued on completion of the plan of arrangement (note 1)		6,581,364			4,174,415
Issued through private placement to directors, officers and employees		1,645,000			1,332,450
Conversion of special warrants		24,827,585			36,000,000
Issued through private placement of flow-through shares		1,775,000			3,550,000
Future tax effect on flow-through shares		-			(1,329,000	)
Share issue costs		-			(2,396,294	)
Future tax effect of the share issue costs		-			891,600
Balance at December 31, 2003		34,828,949		$	42,223,171
Issued through private placement of flow through shares		2,127,207			6,000,002
Share issue costs		-			(264,281	)
Future tax effect of share issue costs		-			108,600
Exercise of stock options		41,667			63,040
Balance at December 31, 2004		36,997,823		$	48,130,532

F-11

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

In December 2004, the Company issued 806,452 common shares on a tax flow-through basis at $3.10 per share for proceeds of $2.5 million. Management and directors subscribed for approximately 13% of the issue. In September 2004, the Company issued 1,320,755 common shares on a tax flow-through basis at $2.65 per share for proceeds of $3.5 million. Management and directors subscribed for 25% of the issue.

Under the terms of these private placements the Company is committed to expend the proceeds on qualifying exploration drilling and seismic prior to December 31, 2005 and renounce the tax benefits to the subscribers by December 31, 2004.

In September 2003, the Company issued 1,775,000 common shares on a tax flow-through basis at $2.00 per share for proceeds of $3.6 million. Management and directors subscribed for 50% of the issue. Under the terms of the private placement the proceeds were expended on qualifying exploration drilling and seismic prior to December 31, 2004.

In March, 2003 the Company completed a private placement of 24,827,585 special warrants for gross proceeds of $36,000,000. The proceeds of this financing were placed in escrow until shareholder approval was received on April 14, 2003. At that time the special warrants were deemed to be exercised for common shares on a one for-one basis without additional consideration. Management and directors subscribed for approximately 10% of the issue.

Stock-based Compensation Plan

Pursuant to Luke Energy’s Stock Option Plan, (“the Plan”), the Company was entitled to reserve for issuance and grant stock options to a maximum of 3.3 million shares on a cumulative basis (not to exceed 10% of the issued and outstanding shares of Luke Energy on an undiluted basis). Options granted under the Plan to date have a term of five years to expiry. Options vest equally over a three-year period starting on the first anniversary date of the grant. The exercise price of each option equals the market price of the Company’s common shares on the date of the grant.

A summary of the status of the Plan at December 31, 2004 and 2003, and changes during the periods ended is presented below:

	2004						2003
	Number			Weighted			Number			Weighted
	of			Average			of			Average
	Options			Exercise Price			Options			Exercise Price
Stock options, beginning of period		2,665,000		$	1.52			-			-
Granted		591,000		$	2.38			3,055,000		$	1.51
Exercised		(41,667	)		(1.04	)		-			-
Cancelled		-			-			(390,000	)	$	1.39
Stock options, end of period		3,214,333		$	1.69			2,665,000		$	1.52
Exercisable, end of period		846,667		$	1.55			-			-

F-12

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

The following table summarizes information about the stock options outstanding at December 31, 2004:

	Options Outstanding at
	December 31, 2004
			Weighted
			Average		Weighted
			Remaining		Average
	Number		Contractual		Exercise
Range of Exercise Prices	of Options		Life		Price
Less than $1.00		643,333		3.14	$	0.81
$1.00 to $2.00		1,980,000		3.69	$	1.77
Greater than $2.00		591,000		4.67	$	2.38
		3,214,333		3.76	$	1.69

	The fair value of each stock option was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions: risk-free interest rate of 5%, dividend yield of 0%, expected life of 5 years, and volatility of 45%. The fair value of options issued in the year was calculated at $652,071.
8.	PER SHARE AMOUNTS
	In computing diluted earnings per share, 124,639 shares were added to the weighted average number of common shares outstanding during the year ended December 31, 2004 for the dilutive effect of all employee stock options and warrants (2003 - 581,480). No adjustments were required to reported earnings from operations in computing diluted per share amounts.
9.	TAXES
	The future income tax liability includes the following temporary differences:

		2004			2003
Capital assets	$	1,961,738		$	928,432
Share issue costs		(582,867	)		(667,817	)
Asset retirement obligations		(171,237	)		(35,139	)
Attributable crown royalty income		(96,850	)		-
Non-capital losses		(55,534	)		(126,626	)
	$	1,055,250		$	98,850

F-13

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

The provision for income taxes differs from the amount computed by applying the combined federal and provincial tax rates to earnings before income taxes. The difference results from the following:

		2004			2003
Earnings before taxes		$	2,170,442		$	756,634
Combined federal and provincial tax rate			38.87	%		40.62	%
Computed “expected” tax		$	843,651		$	307,345
Increase (decrease) in taxes resulting from:
	Non-deductible crown charges, net of ARTC		444,047			29,066
	Non-taxable portion of capital gain (loss)		57,379			(127,866	)
	Non-deductible stock-based compensation expense		271,357			90,059
	Other non-deductible expenses		13,830			9,877
	Effect of change in corporate tax rate		(90,988	)		(50,558	)
	Resource allowance		(377,426	)		32,077
	Attributable crown royalty income		(96,850	)		-
	Large corporations tax		5,000			96,800
Reported income taxes		$	1,070,000		$	386,800

10.	CASH FLOW INFORMATION
	Change in non-cash working capital is summarized below:

	2004			2003
Accounts receivable	$	(2,167,519	)	$	(529,815	)
Accounts payable and accrued liabilities		5,179,134			2,203,148
	$	3,011,615		$	1,673,333
Non-cash working capital - operating	$	(1,008,292	)	$	45,959
Non-cash working capital - investing		4,019,907			1,627,374
	$	3,011,615		$	1,673,333

Amounts actually paid during the period relating to interest expense and capital taxes are as follows:

	2004		2003
Interest paid	$	-	$	2,680
Capital taxes paid	$	101,800	$	-

F-14

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

11.	FINANCIAL INSTRUMENTS
	The financial instruments included in the balance sheets are comprised of accounts receivable and accounts payable and accrued liabilities. The fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments.
	All of the Company’s accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. Purchasers of the Company’s natural gas, crude oil and natural gas liquids are subject to an internal credit review to minimize risk of non-payment.
12.	COMMITMENTS
	At December 31, 2004 the Company had commitments for the lease of office space of approximately $220,000 a year until October 1, 2009.
13.	UNITED STATES ACCOUNTING PRINCIPLES AND REPORTING
	These 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 (“US GAAP”). The significant differences in those principles, as they apply to the Company’s financial statements, are described below.
	a)	Full Cost Accounting
		The Company is subject to a SEC prescribed ceiling test. In determining the limitation on capitalized costs, SEC rules require a 10 percent discounting of after-tax future net revenues from production of proved oil and gas reserves. The future revenues are estimated using year-end prices. To date, application of the SEC prescribed test has not resulted in a write-down of capitalized costs.
	b)	Flow-through Shares
		The Company finances a portion of its activities with flow-through share issues whereby the tax deductions on expenditures are renounced to the share subscribers. Under Canadian GAAP the estimated cost of the tax deductions renounced to shareholders is reflected as a reduction of the stated value of the shares. The SEC requires that when the qualifying expenditures are renounced to the shareholders, the estimated tax cost of the renunciation, less any proceeds received in excess of the quoted value of the shares, is reflected as a tax expense.

F-15

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

c)

Stock-based Compensation

Prior to 2004 the Company used the intrinsic method of accounting for stock options for both Canadian and US GAAP purposes. On January 1, 2004 the Company retroactively changed its method of accounting for stock options to the fair value method. While US GAAP continues to allow the use of either the intrinsic method, as prescribed by APB 25, or the fair value method, as prescribed by SFAS 123, the Company has elected to adopt the fair value method of accounting for stock options for US GAAP purposes. The new method has been applied retroactively with a restatement of prior period US GAAP amounts. This change resulted in a reduction in the US GAAP earnings of $698,113 ($0.02 per share) for the year ended December 31, 2004 and $214,092 ($0.01 per share) for the period ended December 31, 2003.

The following tables provide a reconciliation of earning and retained earnings, and the balance sheet impact for the differences between Canadian GAAP and US GAAP:

			Year Ended		Period Ended
	Note		December 31, 2004		December 31, 2003
Earnings, as reported			$	1,100,442	$	369,834
Accounting for income taxes		(b)		-		(1,329,000	)
Earnings (loss) - US GAAP			$	1,100,442	$	(959,166	)
Earnings (loss) per share - US GAAP			$	0.03	$	(0.03	)

						Increase
As at December 31, 2004		Note		As Reported		(Decrease)			US GAAP
Shareholder’s equity
	Share capital		(b)		48,130,532		1,329,000			49,459,532
	Retained earnings		(b)	$	1,470,276	$	(1,329,000	)	$	141,276

						Increase
As at December 31, 2003		Note		As Reported		(Decrease)			US GAAP
Shareholder’s equity
	Share capital		(b)	$	42,223,171		1,329,000			43,552,171
	Retained earnings		(b)	$	369,834	$	(1,329,000	)	$	(959,166	)

Other disclosures:

Subtotal in Operating Cash Flows

The Company includes a subtotal in cash provided by operating activities in the statements of cash flows. The SEC prohibits the inclusion of this subtotal.

Depletion and Depreciation

Depletion per gross equivalent barrel is calculated by converting natural gas volumes to a barrel of oil equivalent using the ratio of 6 Mcf of natural gas to 1 barrel of oil. Depletion and depreciation as calculated in accordance with US GAAP for the year ended December 31, 2004 is $8.43 per boe (period ended December 31, 2003 - $10.41 per boe).

F-16

LUKE ENERGY LTD.

NOTES TO FINANCIAL STATEMENTS

Periods ended December 31, 2004 and 2003

SAB 106

In September 2004 the SEC issued SAB 106 regarding the application of FAS 143 by oil and gas entities that follow the full cost accounting method. SAB 106 states that after the adoption of FAS 143 the future cash flows associated with the settlement of asset retirement obligations accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling test calculation. As the Company excludes these future cash outflows from its present value of estimated future net cash flows and does not reduce the capitalized oil and gas costs by the asset retirement obligation reflected on the balance sheet, the adoption of SAB 106 in 2004 did not have any impact on the Company’s financial statements, nor did it have an effect on the results of the ceiling test calculation.

Accounting for Variable Interest Entities

In January 2003 the FASB issued Financial Interpretation 46, Accounting for Variable Interest Entities that requires the consolidation of Variable Interest Entities. As the Company does not have any financial interests in other entities, it does not believe FIN 46R results in the consolidation of any additional entities at December 31, 2004.

Accounting of Exchange of Nonmonetary Assets

In December 2004 the FASB issued FAS 153 which deals with the accounting for the exchanges of nonmonetary assets. FAS 153 is an amendment of APB Opinion 29. APB Opinion 29 requires that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. FAS 153 amends APB Opinion 29 to eliminate the exception from using fair market value for nonmonetary exchanges of similar productive assets and introduces a broader exception for exchanges of nonmonetary assets that do not have commercial substance. FAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not believe that the application of FAS 153 will have an impact on the financial statements.

F-17

Statement of Revenue and Operating Expenses of the

Retained Assets to be transferred to

LUKE ENERGY LTD.

Three years ended December 31, 2002

F-18

Report of Independent Registered Public Accounting Firm

To the Directors of

Luke Energy Ltd.

We have audited the statement of revenue and operating expenses of the retained assets to be transferred to Luke Energy Ltd. for each of the years in the three-year period ended December 31, 2002. This financial information is the responsibility of the company’s management. Our responsibility is to express an opinion on this financial information based on our audits

We conducted our audits in accordance with the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial information is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial information. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial information.

In our opinion, this financial information presents fairly, in all material aspects, the revenue and operating expenses of the retained assets to be transferred to Luke Energy Ltd. for each of the years in the three-year period ended December 31, 2002 in conformity with Canadian generally accepted accounting principles.

(signed) "KPMG LLP"

Chartered Accountants

Calgary, Canada

January 20, 2004

F-19

LUKE ENERGY LTD.

Statement of Revenue and Operating Expenses of the Retained

Assetsto be Transferred to Luke Energy Ltd.

(thousands of dollars)

		Period from
		January 1,
		2003 to						Year ended
		February 26,						December 31,
		2003			2002			2001			2000
		(unaudited)
Revenue:
Petroleum and natural gas	$	296		$	1,191		$	1,191		$	1,768
Royalties		(63	)		(200	)		(153	)		(189	)
		233			991			1,038			1,579
Operating expenses		19			120			240			279
Excess of revenue over operatingexpenses	$	214		$	871		$	798		$	1,300

F-20

LUKE ENERGY LTD.

Notes to the Statement of Revenue and Operating Expenses of the Retained

Assets to be Transferred to Luke Energy Ltd.

Years ended December 31, 2002, 2001 and2000

1.	Basis of presentation:
	Pursuant to the arrangement agreement dated January 17, 2003 between KeyWest Energy Corporation (“KeyWest”), Viking Energy Royalty Trust (the “Trust”), Viking KeyWest Inc., Viking Holdings Inc. and Luke Energy Ltd. (“Luke Energy”), KeyWest will transfer its interests in certain petroleum and natural gas properties to Luke Energy (“Retained Assets”).
	This statement has been derived from financial information provided by KeyWest and relates only to the working interests in the Retained Assets.
	This statement includes only those revenue and operating expenses which are directly related to the Retained Assets and does not include any expenses related to general and administrative costs, interest, income and capital taxes or any provisions related to depletion, depreciation or future site restoration and abandonment costs as these amounts are based on the consolidated operations of KeyWest of which these properties only form a part.
2.	Significant accounting policies:
	(a)	Revenue:
		Revenue from the sale of oil, natural gas liquids and natural gas is recorded at the time that the product is produced and sold.
	(b)	Royalties:
		Royalties are recorded at the time the product is produced and sold. Royalties are calculated in accordance with the terms of individual royalty agreements.
	(c)	Operating expenses:
		Operating expenses include amounts incurred to bring the oil and natural gas to the surface, gather, transport, field process and store same. Operating expenses are reflected net of gathering, processing and transportation revenue associated with the properties.

F-21

LUKE ENERGY LTD.

Unaudited Pro Forma Statement of Earnings

Year ended December 31, 2003

Pursuant to a plan of arrangement between Viking Energy Royalty Trust, Viking Holdings Inc., Viking KeyWest Inc., KeyWest Energy Corporation ("KeyWest") and Luke Energy Ltd. (“Luke Energy”), KeyWest transferred interests in certain petroleum and natural gas properties and related facilities (“Retained Assets”) to Luke Energy in exchange for common shares of Luke Energy. On the closing of the arrangement, the common shares of Luke Energy held by KeyWest were distributed to the shareholders of KeyWest.

The accompanying unaudited pro forma statement of earnings for the year ended December 31, 2003 has been prepared by the management of Luke Energy in accordance with the accounting principles generally accepted in Canada. The pro forma statement has been provided to give a reader an indication of the operations of the Retained Assets as if Luke Energy were formed on January 1, 2003 and had acquired the properties on that date.

The pro forma statement of earnings is not necessarily indicative either of the results that actually would have occurred if the events reflected herein had taken place on January 1, 2003 or of the results that may be obtained in the future.

F-22

LUKE ENERGY LTD.

Pro Forma Statement of Earnings

Year ended December 31, 2003

(Unaudited)

(In thousands of dollars except per share amounts)

													Pro Forma
		Luke			Retained								Luke Energy
		Energy Ltd.			Assets			Adjustments		Notes			Ltd.
Revenues:
Oil and gas production	$	1,716		$	296		$	–				$	2,012
Royalties		(435	)		(63	)		(5	)	(a	)		(503	)
Gain on sale of investments		630			–			–					630
Interest		953			–			–					953
		2,864			233			(5	)				3,092
Expenses:
Operating		263			19			–					282
General and administrative		1,134			–			–		(b	)		1,134
Interest		3			–			–					3
Depletion, depreciationand accretion		493			–			52		(d	)		545
		1,893			19			52					1,964
Earnings (loss) before taxes		971			214			(57	)				1,128
Taxes:
Current		97			–			–					97
Future		290			–			64		(e	)		354
		387			–			64					451
Earnings (loss)	$	584		$	214		$	(121	)			$	677
Earnings per share										(f	)	$	0.02

F-23

LUKE ENERGY LTD.

Notes to Pro Forma Statement of Earnings

For the year ended December 31, 2003

(Unaudited)

1.	Basis of presentation:
	The accompanying unaudited pro forma statement of earnings has been prepared by the management of Luke Energy Ltd. ("Luke Energy") in accordance with accounting principles generally accepted in Canada for inclusion in the Form 20-F report.
	Luke Energy was incorporated pursuant to the Canada Business Corporations Act on January 9, 2003 as a wholly-owned subsidiary by KeyWest Energy Corporation ("KeyWest"). Pursuant to a plan of arrangement between Viking Energy Royalty Trust, Viking Holdings Inc., Viking KeyWest Inc., KeyWest and Luke Energy, KeyWest transferred interests in certain petroleum and natural gas properties and related facilities ("Retained Assets") to Luke Energy in exchange for common shares of Luke Energy. On February 26, 2003, on the closing of the plan of arrangement, the common shares of Luke Energy held by KeyWest were distributed to the shareholders of KeyWest on a one for ten basis. Luke Energy began trading on the Toronto Stock Exchange on February 28, 2003.
	The following summarizes the transfer of the Retained Assets, which were initially recorded at KeyWest's net book value as Luke Energy and KeyWest were related parties. The amounts were then adjusted for the booking of the asset retirement obligation and the future tax asset. The results of the operations of the Retained Assets were included in Luke Energy’s reported results from February 26, 2003.

Net assets acquired and liabilities assumed:
Petroleum and natural gas rights	$	2,482,106
Equipment and facilities		1,126,009
Future tax asset		628,550
Site restoration		(62,250	)
	$	4,174,415
Consideration:
Issuance of 6,581,364 common shares	$	4,174,415

The pro forma statement of earnings has been provided to give a reader an indication of the operations of the Retained Assets as if Luke Energy were formed on January 1, 2003 and had acquired the properties on that date. In the opinion of management, the pro forma statement of earnings includes all material adjustments necessary for the fair presentation in accordance with Canadian generally accepted accounting principles. The pro forma statement of earnings is not necessarily indicative either of the results that actually would have occurred if the events reflected herein had taken place on January 1, 2003 or of the results that may be obtained in the future.

F-24

LUKE ENERGY LTD.

Notes to Pro Forma Statement of Earnings

For the year ended December 31, 2003

(Unaudited)

The unaudited pro forma statement of earnings for year ended December 31, 2003 has been prepared from the audited financial statements of Luke Energy for the period from January 9, 2003 (date of incorporation) to December 31, 2003 and the unaudited statement of revenues and operating expenses for the Retained Assets transferred to Luke Energy for the period from January 1, 2003 to February 26, 2003.
The pro forma statement of earnings has been prepared assuming that the transactions described above had been completed on January 1, 2003. The pro forma statement of earnings give effect to the following assumptions and adjustments:
(a)	Certain Retained Assets were acquired by KeyWest in October 2002 and were previously owned by the freehold royalty owner. Therefore, royalties have been adjusted to reflect the contracted royalty rate Luke Energy would have paid if the properties were owned from January 1, 2002.
(b)	General and administrative expenses have been adjusted to reflect estimated costs to be incurred for Luke Energy to operate independently.
(c)	Depletion and depreciation has been calculated using the unit of production method, based upon the net book value of the properties transferred to Luke Energy, production from the properties transferred to Luke Energy for the applicable periods, and reserves of Luke Energy using the January 15, 2003 Reserve Report prepared by an independent engineering firm.
(d)	Luke Energy follows the "Accounting for Asset Retirement Obligations" standard. As a result, the pro forma statements of earnings reflect the application of this standard.
(e)	Future income taxes have been calculated at the enacted rates in effect for the year.
(f)	The loss per share calculations give effect to the issuance of common shares described above as if the shares have been issued on January 1, 2003.

F-25