Luke Energy 20-F 2003 FY Annual report (foreign)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)
¨	REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934
	OR
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the period ended                     December 31, 2003
	OR
¨	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 – 5^th 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, 2003.

34,828,949 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.

Yesý No¨

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

Item 17 ý Item 18 ¨

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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	8
C.	Reasons for the Offer and Use of Proceeds	9
D.	Risk Factors	9

ITEM 4 INFORMATION ON THE COMPANY 16

A.	History and Development of the Company	16
B.	Business Overview	17
C.	Organizational Structure	21
D.	Property, Plant and Equipment	21

ITEM 5 OPERATING AND FINANCIAL REVIEW PROSPECTS 24

A.	Operating Results - Period Ended December 31, 2003	25
B.	Liquidity and Capital Resources	29
C.	Research and Development	30
D.	Trend Information	30
E.	Off-balance Sheet Arrangements	30
F.	Tabular Disclosure of Contractual Obligations	31
G.	Safe Harbor	31

ITEM 6 DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES 31

A.	Directors and Senior Management	31
B.	Compensation	33
C.	Board Practices	33
D.	Employees	34
E.	Share Ownership	34

ITEM 7 MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 35

A.	Major Shareholders	35
B.	Related Party Transactions	36

ITEM 8 FINANCIAL INFORMATION 36

A.	Financial Information	36
B.	Significant Changes	37

ITEM 9	THE OFFER AND LISTING	37
ITEM 10	ADDITIONAL INFORMATION	37

A.	Share Capital	37
B.	Memorandum and Articles of Association	37
C.	Material Contracts	43
D.	Exchange Controls	43
E.	Taxation	43
F.	Dividends and Paying Agents	47
G.	Statement by Experts	48
H.	Documents on Display	48
I.	Subsidiary Information	48

ITEM 11 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKETRISK 48

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	ITEM 12	DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES		48
PART II				48
	ITEM 13	DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES		48
	ITEM 14	MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERSAND USE OF PROCEEDS		48
	ITEM 15	CONTROLS AND PROCEDURES		48
	ITEM 16			49
		A.	Audit Committee Financial Expert	49
		B.	Code of Ethics	49
		C.	Principal Accountant Fees and Services	49
		D.	Exemptions from the Listing Standards for Audit Committees	49
		E.	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	50
	ITEM 17	FINANCIAL STATEMENTS		50
	ITEM 18	FINANCIAL STATEMENTS		50
	ITEM 19	EXHIBITS		50

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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

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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".

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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

ITEM 1IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS

Not Applicable.

ITEM 2OFFER STATISTICS AND EXPECTED TIMETABLE

Not Applicable.

ITEM 3KEY INFORMATION

A.  Selected Financial Data

The financial statements of Luke Energy Ltd. ("Luke" or the "Company") have been prepared in accordance with generally accepted accounting principles in Canada. Except as described in Note 13 to the Company's audited financial statements for 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 financial statements for the period ended December 31, 2003 included herein.

(Amounts stated in Canadian dollars)

	Period ended
Canadian GAAP	Dec. 31, 2003
		($)
Revenue net of royalties		1,280,933
Earnings before taxes		970,726
Net earnings for the period		583,926
Earnings per Common Share – basic and diluted		0.02
Total assets		45,227,643
Net assets		42,814,715
Capital stock		42,223,171
Number of shares		34,828,949
Dividends		NIL
Long term debt		NIL

 Reconciliation of reported earnings (loss) as a result of the differences between Canada and the United States accounting principles for the period ended December 31, 2003 is as follows:

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		Period ended
U.S. GAAP		Dec. 31, 2003
Earnings for the period, as reported		583,926
Estimated tax cost of the renunciation of tax benefits on expenditures(1)		(1,329,000	)
Earnings (loss) for the period		(745,074	)
Loss per share – basic and diluted	$	0.03

(1)	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. The estimated cost of the tax deductions renounced to shareholders had been reflected as a reduction of the stated value of the shares. The SEC requires that when the qualifying expenditures are incurred and 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.
	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 June 24, 2004, 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 $0.7446 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.

	2003			2004
	December	January	February	March	April	May
High	0.7738	0.7880	0.7629	0.7645	0.7637	0.7364
Low	0.7460	0.7496	0.7439	0.7418	0.7293	0.7158
Average	0.7618	0.7719	0.7520	0.7527	0.7453	0.7253
End of Period	0.7738	0.7539	0.7460	0.7634	0.7293	0.7317

	3. The average exchange rate for the fiscal year ending December 31, 2003, calculated by using the average of the exchange rates in effect on the last day of each month during the period indicated, was $0.7186 U.S. = $1.00 Canadian. During the fiscal year ending December 31, 2003, the exchange rate high was $0.7738 U.S. = $1.00 Canadian, the exchange rate low was $0.6349 U.S. = $1.00 Canadian and the exchange rate at the end of period was $0.7738 U.S. = $1.00 Canadian.
B.	Capitalization and Indebtedness
	Not Applicable.

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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. The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Company's reserves will depend not only on its ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. The Company may not be able to continue to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or par ticipations are identified, the Company 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 the Company.

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, the Company is not fully insured against all of these risks, nor are all such risks insurable. Although the Company maintains liability insurance in an amount that it considers consistent with industry practice, the nature of these risks is such that liabilities could exceed policy limits, in which event the Company could incur significant costs that could have a material adverse effect upon its financial condition. Oil and natural gas product ion operations are also subject to 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.

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Reserve Estimates

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 at tempts 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 its 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 could result in variations in the estimated reserves and such variations could be material.

In accordance with applicable Canadian 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 may vary from the estimates contained in GLJ's evaluation of the Company's oil and natural gas reserves effective December 31, 2003 (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.

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 its control. The Company's ability to market its natural gas may depend upon its 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

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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 substant ial 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.

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.

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. To the extent the Company is not the operator of its oil and gas properties, the Company will be dependent on such operators for the timing of activities related to such properties and will be largely unable to direct or control the activities of the operators.

Failure to Realize Anticipated Benefits of Acquisitions and Dispositions

The Company makes 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 the Company's ability to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses 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, non-core assets are periodically disposed of, so that the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such non-core assets, certain non-core assets of the

11

Company, if disposed of, could be expected to realize less than their carrying value on the financial statements of the Company.

Substantial Capital and Additional Funding 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. Any 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.

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

Issuance of Debt

From time to time the Company may enter into transactions to acquire assets or the shares of other corporations. 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.

Hedging

From time to time the Company may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Company will not benefit from such increases and the Company may nevertheless be obligated to pay royalties on such higher prices, even though not received by it, after giving effect to such agreements. Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, the Company will not benefit from the fluctuating exchange rate.

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Competition

Oil and gas exploration is intensely competitive in all its phases and involves a high degree of risk. The Company competes 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. The Company's competitors include oil and natural gas companies that have substantially greater financial resources, staff and facilities than those of the Company. The Company's ability to increase reserves in the future will depend not only on its ability to explore and develop its present properties, but also on its 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.

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. The Company's operations may require licenses from various governmental authorities. There can be no assurance that the Company will be able to obtain all necessary licenses and permits that may be required to carry out exploration and development at its projects and the obtaining of such licences and permits may delay operations of the Company.

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." The Company's exploration and production facilities and other operations and activities emit a small amount of greenhouse gases which may subject the Company 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 Cha nge and Emissions Management Act (Alberta) (yet to be proclaimed), may require the reduction of emissions or emissions intensity produced by the Company's operations and facilities. The direct or indirect costs of these regulations may adversely affect the business of the Company.

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. 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 potenti ally 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 the Company to incur costs to remedy such discharge. Although the Company believes that it is in material compliance with current applicable environmental regulations, non-compliance with environmental laws may result in a curtailment of

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production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect the Company's financial condition, results of operations or prospects.

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, blow outs, property damage, personal injury or other hazards. Although prior to drilling the Company will obtain insurance 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.

Management of Growth

The Company may be subject to growth-related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Company to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expend, train and manage its employee base. The inability of the Company to deal with this growth could have a material adverse impact on its business, operations and prospects.

Expiration of Licences and Leases

The Company's properties are held in the form of licences and leases and working interests in licences and leases. If the Company or the holder of the licence or lease fails to meet the specific requirement of a licence or lease, the licence or lease may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence or lease will be met. The termination or expiration of the Company's licences or leases or the working interests relating to a licence or lease may have a material adverse effect on the Company's results of operations and business.

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.

14

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.

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 consolidated 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 capit alized 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 theCanada Business Corporations Act 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 theCanada Business Corporations Act.

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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 Company does not have key person insurance in effect for any member of management. 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.

ITEM 4INFORMATION ON THE COMPANY

A. History and Development of the Company

Luke Energy Ltd. was incorporated pursuant to theCanada Business Corporations Acton 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”), Viking Holdings Inc., Viking KeyWest Inc., KeyWest and the Company, KeyWest transferred interests in certain petroleum and natural gas properties and related facilities (the "Retained Assets") to the Company in exchange for the Company's common shares ("Common Shares"). On February 26, 2003, the closing of the plan of arrangement, the Common Shares held by KeyWest were distributed to the shareholders of KeyWest on a one for ten basis.

Since February 28, 2003, the Company's Common Shares have been listed and posted for trading on the Toronto Stock Exchange under the symbol "LKE".

The head office and principal office of the Company is located at Suite 1200, 520 – 5^th Avenue S.W. Calgary, Alberta, CANADA T2P 3R7. The telephone number is 403-261-4811.

The business of the Company is the acquisition, development, production and marketing of, and exploration for, oil and natural gas 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.

Financings

Three successful financings were completed during 2003, which collectively netted the Company approximately $38.5 million.

The initial financing raised $1.3 million in start-up capital through the sale to Company insiders of 1.6 million Common Shares at 81 cents per share.

A subsequent major financing in March raised net proceeds of approximately $33.8 million. A total of 24.8 million Common Shares were sold at $1.45 per share and insiders subscribed for 10% of the issue.

Finally, a September financing netted approximately $3.4 million for the Company’s account. Insiders bought 50% of the 1.8 million Common Shares that were issued at $2.00 per share on a "flow through" basis.

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Historical Principal Capital Expenditures/Divestitures

Capital expenditures for the period ended December 31, 2003 were $4.8 million. Over 70% of these expenditures were incurred for the Marten Creek project (the Company’s first core area of operations) in northern Alberta. The Company drilled the first well of a ten well drilling program at Marten Creek prior to December 31, 2003.

Current and Planned Capital Expenditures/Divestitures

The Company's 2004 capital expenditure program is estimated to be $26 million, and will be financed by working capital and cash flow. The Company incurred $10.9 million of the planned capital expenditure program in the first quarter of 2004. These expenditures were primarily related to drilling the remaining 9 wells of the Marten Creek project, located in northern Alberta, and the subsequent costs of bringing the wells onto production. The Marten Creek drilling program resulted in 8 successful gas wells of which seven were tied in and on-stream mid-March 2004 at an aggregate rate of 4 million cubic feet a day. The remaining $15 million of the capital expenditure program has been allocated as follows: $6 million for land acquisitions; $2 million for seismic; $5 million for drilling and equipping seven wells located primarily in northeast British Columbia; and $2 million fo r facilities and flow-lines related to the drilling program.

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. During its first year the Company arranged financing, assembled personnel and commenced operations.

During the first period of operations ended December 31, 2003 oil and gas sales were $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

The Company received an average of $35.08 Cdn per barrel for its oil in 2003. The Company’s production averaged 88 bbls/d of light gravity oil from Bassano (30º API) and Bashaw (37º API).

The Company’s natural gas price averaged $6.47 Cdn per mcf in 2003. The Company’s natural gas production averaged 380 mcf/d in 2003. Luke sold its natural gas to Pan-Alberta Gas, Progas Limited and Nexen Marketing during the year.

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The Company plans to sell its Marten Creek gas on the daily spot market.

Applicable Government Regulation

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation and marketing) imposed by legislation enacted by various levels of government and with respect to pricing and taxation of oil and natural gas by agreements among the governments of Canada, Alberta, British Columbia and Saskatchewan, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect the Company's operations in a manner materially different than they would affect other oil and gas companies of similar size. All current legislation is a matter of public record and the Company is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the pri ncipal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing – Oil and Natural Gas

The price of oil is determined by negotiation between buyers and sellers. Such price depends in part on oil quality, prices of competing oils, distance to market, the value of refined products and the supply/demand balance. Oil exporters are entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the "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 NEB export license and Governor in Council approval.

In Canada, the price of natural gas is determined by negotiation between buyers and sellers. Exporters are free to negotiate export contracts provided that they meet certain criteria prescribed by the NEB and the Government of Canada. Natural gas exports for a term of less than 2 years or for a term of 2 to 20 years (in quantities of not more than 30,000 m³/day) must be made pursuant to an NEB order. Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an NEB export license and Governor in Council approval.

The governments of Alberta and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere based on such factors as reserve ability, transportation arrangements and market considerations.

The North American Free Trade Agreement

The North American Free Trade Agreement ("NAFTA") among the governments of Canada, United States of America and Mexico became effective on January 1, 1994. NAFTA carries forward most of the material energy terms that are contained in the Canada – United States Free Trade Agreement. Canada continues to remain free to determine whether exports of energy resources to the United States 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 domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price; or (iii) disrupt normal channels of supply. All three co untries are prohibited from imposing minimum export or import price requirements.

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

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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.

Provincial Royalties and Incentives

In addition to federal regulation, each province has legislation and regulations that govern land tenure, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur and natural gas 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 subject to certain provincial taxes and royalties. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date and the type or quality of the petroleum product produced.

From time to time the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs often provide for royalty rate reductions, royalty holidays and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry.

Regulations made pursuant to theMines and Minerals Act (Alberta) provide various incentives for exploring and developing oil reserves in Alberta. Oil produced from horizontal extensions commenced at least 5 years after the well was originally spudded may also qualify for a royalty reduction. A 24-month, 8,000 m³ exemption is available to production from a well that has not produced for a 12-month period if production is resumed after February 1, 1993. As well, oil production from eligible new field and new pool wildcat wells and deeper pool test wells spudded or deepened after September 30, 1992 is entitled to a 12-month royalty exemption (to a maximum of $1 million). Oil produced from low productivity wells, enhanced recovery schemes (such as injection wells ) and experimental projects is also subject to royalty reductions.

The Alberta government has also introduced a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 30, 1992. The new oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown has a base rate of 10% and a rate cap of 35%.

In Alberta, the royalty reserved to the Crown in respect of natural gas production, 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 reference or corporate average price. Natural gas produced from qualifying exploratory gas wells spudded or deepened after July 31, 1985 and before June 1, 1988 is eligible for a royalty exemption for a period of 12 months, up to a prescribed maximum amount. Natural gas produced from qualifying intervals in eligible gas wells spudded or deepened to a depth below 2,500 meters is also subject to a royalty exemption, the amount of which depends on the depth of the well.

In Alberta, a producer of oil or natural gas is entitled to a credit against the royalties payable to the Crown by virtue of the ARTC program. The ARTC rate is based on a price sensitive formula and the ARTC rate varies between 75% at prices at and below $100 per m³ and 25% at prices at and above $210 per m³. In general, the ARTC rate is 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 a corporation claiming maximum entitlement to ARTC will

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generally not be eligible for ARTC. The rate will be established quarterly based on the average "par price", as determined by the Alberta Department of Energy for the previous quarterly period.

On December 22, 1997, the Alberta government announced that it was conducting 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 preclude companies that pay less than $10,000 in royalties per year and non-corporate entities from qualifying for the program. Such rules will not presently preclude the Company from being eligible for the ARTC program.

In November 2003, theIncome Tax Act(Canada) was amended to provide the following initiatives applicable to the oil and gas industry to be phased in over a five year period: (i) a reduction of the federal statutory corporate income tax rate on income earned from resource activities from 28 to 21%, beginning with a one percentage point reduction effective January 1, 2003, and (ii) a deduction for federal income tax purposes of actual provincial and other Crown royalties and mining taxes paid and the elimination of the 25% resource allowance. In addition, the percentage of ARTC that the Company will be required to include in federal taxable income will be 5% in 2003; 12.5% in 2004; 17.5% in 2005; 32.5% in 2006; 50% in 2007; 60% in 2008; 70% in 2009; 80% in 2010; 90% in 2011, and 100% in 2012 and beyond.

In Saskatchewan, for Crown royalty and freehold production tax purposes, crude oil is considered either "heavy oil", "southwest designated oil" or "non-heavy oil other than southwest designated oil." The conventional royalty and production tax classifications ("fourth tier oil" introduced October 1, 2002, "third tier oil", "new oil" or "old oil") of oil production are applicable to each of the three crude oil types. The Crown royalty and freehold production tax structure for crude oil is price sensitive and varies between the base royalty rates of 5% for all "fourth tier oil" to 20% for "old oil". Marginal royalty rates are 30% for all "fourth tier oil" to 45 % for "old oil".

Natural gas is considered either "non-associated gas" or "associated gas". The royalty and production tax classifications of gas production ("fourth tier gas" introduced October 1, 2002, "third tier gas", "new gas" and "old gas") are applicable to each of the two gas types. The Crown royalty and freehold production tax for gas is price sensitive and varies between the base royalty rate of 5% for "fourth tier gas" and 20% for "old gas". The marginal royalty rates are between 30% for "fourth tier gas" and 45% for "old gas".

On October 1, 2002 a number of changes were made to the royalty and tax regime in Saskatchewan as follows:

· A new Crown royalty and freehold production tax regime applicable to associated natural gas (gas produced from oil wells) that is gathered for use or sale. The royalty/tax will be payable on associated natural gas produced from an oil well that exceeds approximately 65 thousand cubic metres in a month.

· A modified system of incentive volumes and maximum royalty/tax rates applicable to the initial production from oil wells and gas wells with a finished drilling date on or after October 1, 2002 was introduced. The incentive volumes are applicable to various well types and are subject to a maximum royalty rate of 2.5% and a freehold production tax rate of zero percent.

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· The elimination of the re-entry and short section horizontal oil well royalty/tax categories. All horizontal oil wells with a finished drilling date on or after October 1, 2002 will receive the "fourth tier" royalty/tax rates and new incentive volumes.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licenses and permits for varying terms and on conditions set forth in provincial legislation including requirements to perform specific work or make payments. Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation. Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations. In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage and the imposition of material fines and penalties.

Environmental legislation in Alberta has been consolidated into theEnvironmental Protection and Enhancement Act (Alberta) (the "APEA"), which came into force on September 1, 1993. The APEA imposes stricter environmental standards, requires more stringent compliance, reporting and monitoring obligations and significantly increases penalties. The Company anticipates making increased expenditures of both a capital and an expense nature as a result of the increasingly stringent laws relating to the protection of the environment and will be taking such steps as required to ensure compliance with the APEA and similar legislation in other jurisdictions in which it operates. The Company believes that it is in material compliance with applicable environmental laws and regulations. The Company also believes that it is reasonably likely tha t the trend towards stricter standards in environmental legislation and regulation will continue.

C.	Organizational Structure
	The Company has no subsidiaries.
D.	Property, Plant and Equipment

Principal Producing Properties of the Company

The following is a summary and description of the Company’s principal oil and natural gas properties as at December 31, 2003. All of the Company’s 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 January 1, 2004 reserve evaluation (the "GLJ Report") completed by the Company's independent engineering consultants, Gilbert Laustsen Jung Associates Ltd. Unless otherwise specified, gross and net acres and well count information are as at December 31, 2003.

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				Proved-	Probable
	Average			Developed	Net
Property	Working	Major	2003 Average	Net Reserves*	Reserves
Name	Interest	Product	Production	(MBOE)	(MBOE)
Bassano	48%	Oil & Gas	78	150	34
Bashaw	50%	Oil & Gas	36	137	15
Marten Creek	100%	Gas	-	-	116
Other	Various	Gas	-	60	17
Total			114	347	182

* There are no undeveloped proved reserves at January 1, 2004.

Bassano, Alberta

This property is located 90 miles southeast of Calgary. The Company holds an average 48% working interest in six producing Belly River gas wells and a 50% working interest in a producing Glauconite oil well. The Company also holds an average 46% working interest in Belly River gas rights underlying 3,840 total gross acres of land. The Company’s share of forecast production from the area for 2004 is 62 boepd.

Bashaw, Alberta

Bashaw is located approximately 110 miles northeast of Calgary. In 2003, the Company’s working interests were comprised of 50% in two producing light gravity Nisku oil wells plus 100% in 880 acres of undeveloped lands. Subsequent to year-end the Company acquired the remaining 50% interest in the two oil wells and plans to change out the pumps in both wells to enhance the productivity of the wells. The pump changes are planned for the second quarter of 2004. The Company’s share of forecast production from the area for 2004 is 66 boepd.

Marten Creek, Alberta

Marten Creek is a relatively shallow (1,925 feet) multi-zone Cretaceous natural gas prospect located about 150 miles north of the City of Edmonton and it is 100% owned and operated by the Company. During 2003 the Company purchased and shot about 325 miles of 2D seismic data in the Marten Creek area. Subsequently, the Company acquired some 11,000 acres of land to capitalize on a number of prospective leads identified on the seismic data. A drilling program was initiated just prior to year-end. The first well was drilled in 2003 but was completed and tied-in during the first quarter of 2004 and probable reserves were assigned (see Item 4A under the caption "Current and Planned Capital Expenditures/Divestitures" for a discussion on expenditures related thereto). Nine more wells were drilled in the first quarter of 2004 with an 80% success rate for the project. Pipelines together with a field compressor were constructed during the first quarter of 2004 to tie the wells into a nearby main line that is owned by a mid-stream processor. Production from these wells came on stream mid-March 2004 at 3.1 mmcf/d.

The foregoing properties account for 85% of the Company’s total net proved reserves, all of which are located in Western Canada. The remaining reserves consist of minor interests at Spirit River, Alberta.

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Drilling Activity

Just prior to year-end, the Company drilled the first successful well in the Company’s ten well drilling program on its 100%-owned Marten Creek project. The remaining nine wells were drilled in the first quarter of 2004 with an overall success rate of 80%. Seven of the eight wells were tied-in prior to spring break-up at an aggregate rate of 3.1 mmcf/d.

In addition, during 2003 the Company granted a third party the right to drill two wells to earn an interest in lands owned by the Company in western Alberta. One well was successfully completed as a gas well. The Company retains a royalty on production until the well achieves payout and will be entitled to a 26% share of production thereafter. The Company plans to drill another six to seven wells in 2004 primarily in northeastern British Columbia.

Land Holdings

As part of the Company’s formation, Viking Energy Royalty Trust rolled 100% of its interest in 11,720 acres into the Company. The majority of this acreage block was subsequently farmed out, with the Company retaining an average 65% working interest in the lands.

The Company was an active participant at Crown land sales in the latter half of 2003. The Company focused on establishing an acreage position in Marten Creek – its new gas exploration area in northern Alberta. As a result, the Company’s undeveloped land inventory at year-end increased to an average 81% interest in 20,500 gross undeveloped acres (16,600 net).

At December 31, 2003, the Company’s lands were valued at $2.9 million by Seaton-Jordan Associates Ltd. (the “Seaton Jordon Report”), an independent land consulting firm. This is up from the $1.0 million attributed to the Company’s lands in the Seaton-Jordan Report of a year ago.

The Company's undeveloped land inventory at May 31, 2004 was 21,220 gross acres (16,711 net). The Company will continue to aggressively build its undeveloped land inventory in 2004, both in Marten Creek and in new project areas being developed by the Company’s exploration team.

Oil And Gas Wells

The following table summarizes the Company's working interest as at May 31, 2004 in its principal producing wells and in non-producing wells which are believed capable of production, based on the GLJ Report.

Oil Wells				Natural Gas Wells
Producing		Non-Producing		Producing		Non-Producing
Gross	Net	Gross	Net	Gross	Net	Gross	Net

Alberta 3.0 1.5 - - 13.0 10.2 1 0.1

(1) "Gross Wells" refers to all wells in which the Company has an interest;

(2) "Net Wells" refers to the aggregate of the percentage interest of the Company Energy in the Gross Wells.

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Reserves

Summary of Oil and Gas Reserves
Working Interest after Royalties
at Constant Prices and Costs

	January 1, 2004(1)		January 1, 2003(2)
	Oil and Liquids
	(Mbbl)	Natural Gas (Mmcf)	Oil and Liquids (Mbbl)	Natural Gas (Mmcf)
Proved-Developed(3)	207	842	184	899
Probable(4)	28	922	18	221
Total	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)	There are no undeveloped proved reserves at January 1, 2004 nor January 1, 2003.
(4)	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

	Period Ended		Year Ended(1)		Year Ended(1)
	December 31, 2003		December 31, 2002		December 31, 2001
	Oil and NGL's	Gas	Oil and NGL's	Gas	Oil and NGL's	Gas
	(Bbl)	(Mmcf)	(Bbl)	(Mmcf)	(Bbl)	(Mmcf)
Canada	19	88	24	11	25	14

Notes:

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

ITEM 5OPERATING 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 should be read in conjunction with the audited financial statements of the Company for the period ended December 31, 2003, together with the notes related thereto. The financial statements for the Company have been prepared in accordance with generally accepted accounting principles in Canada. Except as described in Note 13 to the Company's financial statements for the period ended December 31, 2003, there are no material differences, for the purposes of these financial statements, between accounting principles generally accepted in Canada and the United States.

Critical Accounting Estimates

Significant accounting policies are contained in note 2 to the financial statements for the period ended December 31, 2003. The following discusses the accounting estimates that are critical in determining the reported financial results.

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Full Cost Accounting

The Company follows the full cost method of accounting as prescribed by Accounting Guideline #16 issued by the Canadian Institute of Chartered Accountants ("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 proved 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 gain or loss except where such disposal is a significant portion of the reserves.

An alternative method of accounting for 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 earnings 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 depreciation 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.

Stock-based Compensation

The stock option plan provides for granting of stock options to directors, officers, employees and consultants. Stock options granted have a maximum term of five years to expiry and vest equally over a three-year period. The exercise price of each stock option granted is determined as the closing market price of the common shares on the day prior to the day of the grant. Each stock option granted permits the holder to purchase one common share at the stated exercise price. The Company does not record a compensation expense for stock options granted to directors, officers and employees. If the Company had used the fair-value method to account for its stock based compensation to directors, officers and employees, an expense of $214,092 would have been charged to net earnings in 2003.

A. Operating Results - Period Ended December 31, 2003

The Company was incorporated on January 9, 2003 as a wholly-owned subsidiary of KeyWest. Pursuant to a plan of arrangement between Viking, Viking Holdings Inc., Viking KeyWest Inc., KeyWest

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and the Company, KeyWest transferred the Retained Assets to the Company in exchange for Common Shares. The transfer of the assets was recorded at KeyWest’s net book value as the Company and KeyWest were related parties.

Revenue

Oil and gas revenues for the period ended December 31, 2003 were $1,715,620. As the Company’s Marten Creek drilling program did not commence until late December, sales volumes for the reporting period relate only to those properties acquired from KeyWest on February 26, 2003. Volumes for the period were 152 boepd which was in line with management’s expectations for these properties. The Company’s average oil price was $35.08 per barrel while gas averaged $6.47 per mcf, reflecting the strong commodity prices during the period.

The Company’s strategy is to grow through a combination of low to medium risk exploration projects and acquisitions. Oil and gas revenues for 2004 are expected to be significantly higher with the gas volumes from the Marten Creek drilling program coming on-stream in late March. Additional sales volumes are expected from other internally generated exploration projects already underway. The engineering group continues to evaluate acquisition opportunities, however due to the highly competitive market at present, growth in this area is difficult to forecast.

Royalties

Royalty expense for the period ended December 31, 2003 was $434,687 or $9.28 per boe. Royalty expense as a percentage of production revenue was consistent throughout the period at 25%.

Operating Expenses

Operating expenses for the period ended December 31, 2003 were $262,754 or $5.61 per boe. Operating expenses were consistent over the period on a dollar basis as they generally reflected fixed costs related to the production acquired from KeyWest and thus did not vary significantly with changes in production levels.

Operating costs for 2004 are expected to increase concurrently with production growth but are not expected to exceed $7.00 per boe with the Marten Creek wells coming on-stream. Operating expenses will vary on a per boe basis with production increases from other internally generated projects or from acquisitions.

General and Administrative Expenses

The Company has strategically enhanced staffing levels and space requirements to grow its operations, resulting in relatively high general and administrative expenses for current production levels. General and administrative expenses were $1,134,408 for the period ended December 31, 2003 as summarized below:

Gross expense	$	1,369,026
Operator recoveries		(46,143	)
Capitalized expenses		(188,475	)
Net expense	$	1,134,408

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Interest Income and Gain on Sale of Marketable Securities

For the period ended December 31, 2003, the Company’s return on invested cash balances was 5.6%. This relatively high rate was achieved through interest income of $953,464 (or approximately 3.4%) earned on term deposits, investment grade commercial paper and Government of Canada bonds, and also through a $629,575 gain realized on the Company’s sale of its Government of Canada bonds during the period.

Depletion, Depreciation and Asset Retirement Obligation

The provision for depletion, depreciation, and accretion for the period ended December 31, 2003 was $493,404 or $10.54 per boe. The provision increased from $8.78 per boe in the first quarter to a year-end rate of $10.54 per boe due to facility upgrades and geological and geophysical costs that do not immediately result in reserve increases. The following table summarizes the provision:

Depletion and depreciation of petroleum and natural gas properties	$	463,000
Depreciation of office furniture and equipment		25,934
Accretion of asset retirement obligation		4,470
Total depletion, depreciation and accretion	$	493,404

Included in the depletion and depreciation of petroleum and natural gas properties is $8,416 representing the depletion on the capitalized asset retirement obligation of $106,460 for the period ended December 31, 2003.

Taxes

Current taxes of $96,800 for the period ended December 31, 2003 relate exclusively to the federal Large Corporations Tax. The provision for future taxes of $290,000 is 30% of pre-tax earnings to December 31, 2003 and reflects that the sale of the Government of Canada bonds resulted in a capital gain which is 50% taxable.

As at December 31, 2003 the Company had approximately $10.3 million of accumulated tax pools that are available for deduction against future earnings.

			Annual
			Deduction
		$000’s	Rate
Canadian exploration expense	$	517	100	%
Canadian development expense		279	30	%
Canadian oil & gas property expense		5,466	10	%
Undepreciated capital cost		1,838	20% - 30	%
Share issue costs		1,887	20	%
Non-capital losses		353	100	%
	$	10,340

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Capital Expenditures

Capital expenditures for the period ended December 31, 2003 totalled $4.8 million as summarized in the table below. The land costs were incurred for the Marten Creek project. Seismic costs were incurred for the Marten Creek project and the northeastern British Columbia gas prospects. Three quarters of the drilling, equipping, facilities and flowline expenditures were also for the Marten Creek project. The remainder of the costs were related to the Company’s Bashaw and Bassano properties.

Land	$	2,077,054
Seismic		1,064,144
Drilling and equipping		953,070
Facilities and flowlines		564,614
Corporate		175,983
	$	4,834,865

Financial Reporting and Regulatory Changes

New and amended standards described below were implemented by the Company in 2003 with the following impact:

Asset Retirement Obligations

CICA issued Section 3110 which harmonized Canadian GAAP with SFAS No. 143 "Accounting for Asset Retirement Obligations". The new standard requires that companies recognize the present value of the liability associated with future site reclamation costs in the financial statements at the time when the liability is incurred. The new Canadian standard is effective for fiscal years beginning on or after January 1, 2004, however the Company adopted the standard upon formation. As a result the Company has recorded a liability for asset retirement obligation of $110,930, an increase to capital assets of $106,460 and an accretion expense of $4,470 (included in the depletion, depreciation and accretion expense on the statement of earnings).

Full Cost Accounting

In September 2003, the CICA issued Accounting Guideline 16 "Oil and Gas Accounting – Full Cost" to replace CICA Accounting Guideline 5. The new guideline proposes amendments to the ceiling test calculation applied by the Company. The new guideline is effective for fiscal years beginning on or after January 1, 2004. The Company implemented this new guideline in 2003 in accordance with transitional provisions that encouraged early adoption. Implementation of this new guideline did not impact the Company's financial results for 2003.

Certain new and amended standards are expected to impact the Company in 2004 as follows:

Continuous Disclosure Obligations

On March 31, 2004, National Instrument 51-102 "Continuous Disclosure Obligations" came into effect. The instrument mandates shorter reporting periods for filing of, and enhanced disclosure in, annual and interim financial statements, MD&A and Annual Information Forms.

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Stock Based Compensation

In September 2003, the CICA issued an amendment to section 3870 "Stock based compensation and other stock based payments". Effective for fiscal years beginning on or after January 1, 2004, the amendment requires that companies measure all stock based payments using the fair value method of accounting and recognize the compensation expense in their financial statements which illustrates the impact on the earnings if the compensation expense had been booked.

Quarterly Information

($000’s except per share amounts)

		Gross		Cash Flow
		Production		From		Per				Per
2003		Revenue		Operations		Share(1)		Earnings		Share (1)
Q1	$	266	$	68	$	0.01	$	5	$	0.00
Q2		537		287		0.01		85		0.00
Q3(2)		487		772		0.02		464		0.01
Q4		426		248		0.01		29		0.00
Total	$	1,716	$	1,375	$	0.05	$	583	$	0.02

¹The sum of the quarterly per share amounts may not necessarily equal the annual per share amounts due to the different weightings of shares issued during the year.

²Cash flow and earnings for the third quarter were positively impacted by the gain on sale of Government of Canada bonds.

B. Liquidity and Capital Resources

The Company is well capitalized for growth with working capital of $24.6 million as at March 31, 2004 ($35,000,000 as at December 31, 2003) and an unused $2 million credit facility.

Pursuant to the terms of the credit facility, any amounts owing will revolve until June 30, 2004 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. Loans under the facility may be made by way of prime based loans. A standby fee of 0.375% per annum is levied on the unused portion of the facility.

The remaining 2004 planned capital expenditure program of $15 million will be funded by working capital and credit facility borrowings. The Company's strategy continues to be focused on adding production through a combination of low to medium risk exploration projects. Although the engineering group evaluates acquisition opportunities as they arise, the current capital budget does not include a forecasted acquisition due to the highly competitive market at present.

On February 26, 2003, the Company raised $1.3 million by issuing 1.6 million shares to directors, officers, and employees. In March the Company completed a private placement of 24,827,585 special warrants for gross proceeds of approximately $36 million. Management and directors subscribed for approximately 10% of the issue. All of such special warrants were subsequently converted to Common Shares on April 14, 2003. In September, the Company issued 1,775,000 Common Shares on a tax flow-through basis at $2.00 per share for gross proceeds of $3,550,000. Management and directors subscribed for 50% of the issue.

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At May 31, 2004, the Company had 34,828,949 Common Shares outstanding and 2,732,000 stock options outstanding. As at December 31, 2003, the numbers were 34,828,949 Common Shares outstanding and 2,665,000 stock options. Cash flow for 2004 is forecasted at $3.7 million. It is also expected that the Company will have working capital of $16 million as at December 31, 2004.

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.

D. Trend Information

There are a number of trends that have been developing in the oil and gas industry during the last three years that appear to be shaping the near future of the business. The first trend is the incorporation and growth of a number of junior public and private oil and gas companies. These companies are currently able to raise capital and have access to qualified technical staff. This situation is a direct result of the previous consolidation phase of the industry. The second trend is that oil prices have remained high for an extended period of time and, while subject to large fluctuation due to political events, appear to be supported by continuing increased worldwide demand and actual or potential supply disruptions in Venezuela and the Middle East. The third trend is that due to strong demand and reducing supply, natural gas will likely receive higher average prices over the next f ive years than it has received in the last five years.

Oil Prices

The resolve of the Organization of Petroleum Exporting Countries (“OPEC”) to steadily cut production throughout 2001 stabilized the WTI oil price in the low U.S. $20s per barrel level. Meanwhile unrest and supply disruptions in Venezuela, Nigeria and the Middle East during 2002 and early 2003 caused the price to rise, reaching a peak of just under U.S. $40 per barrel prior to the war in Iraq. Since the war in Iraq prices initially decreased to approximately U.S. $25.00 per barrel and then strengthened due to higher world demand, especially in Asia, and lower inventory levels. Oil prices are now generally forecasted to remain at or above U.S. $30.00 per barrel throughout the balance of 2004.

Gas Prices

The overall supply and demand situation for natural gas in North America has been relatively firm over the past four years and as a result price volatility has been more extreme compared to the last 20 years. In early 2001 gas prices reached extremely high levels as a result of a supply shortage which resulted in high exploration activity throughout North America. The short-term result was increased natural gas deliverability, which coupled with an unusually mild winter resulted in a steady increase in natural gas supply. As a result, natural gas prices declined continuously throughout 2001. This trend reversed throughout 2002 and as a result of a colder than normal winter in the northeastern United States gas prices spiked again to as high as U.S. $9.00/mmbtu by February 2003. Prices remained high throughout 2003 due to concerns about North American storage inventory levels and a lack in confidence in North American supply prospects. Prices are forecast to remain at the U.S. $4.75 to $6.00 per mmbtu level for the foreseeable future.

E. Off-balance Sheet Arrangements

The Company has no off-balance sheet arrangements.

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F. Tabular Disclosure of Contractual Obligations

As at December 31, 2003, the Company had no material contractual obligations.

G. Safe Harbor

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

ITEM 6DIRECTORS, 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 and Business Experience	Director Since
Ronald L. Belsher(2)(3) Calgary, Alberta	Director	Partner in Collins Barrow Calgary LLP, Chartered Accountants, since 1977.	January 9, 2003
Mary Blue Calgary, Alberta	President, Chief Operating Officer and Director	President and Chief Operating Officer of the Company. Prior thereto, Executive Vice-President of KeyWest Energy Ltd. 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
David Crevier(1)(3) Montreal, Quebec	Director	Partner in the Montreal law firm of Colby, Monet, Demers, Delage & Crevier. Mr. Crevier is also a director of Yorbeau Resources Inc., Cancor Mines Inc., Lafayette Picker Mills Limited, Diagem International Resource Corp. and Diagnos Inc.	January 9, 2003
Alain Lambert(2) West Bolton, Quebec	Director	Principal of One and Company (an investors relations firm) since January 2002; prior thereto, President of Triology Integrated Investor Relations Inc. from July 1998; President Tokenhouse Capital & Research Inc. from November 1994 to July 1998. Mr. Lambert is also a director of Lyrtec Inc., Damian Capital Inc., Canadian Public Venture Capital I Inc., Canadian Public Venture Finance I Inc. and Vanguard Response Systems Inc.	January 9, 2003
Hugh Mogensen(1) Saanichton, BC	Chairman of the Board and Director	Independent Business Executive and Consultant to the natural resources industry since May 1986. Mr. Mogensen is also a director of Goose River Resources and Queenstake Resources.	January 9, 2003

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Name and
Municipality of
Residence	Office Held	Principal Occupation and Business Experience	Director Since

Harold V. Pedersen(2) Calgary, Alberta	Chief Executive Officer and Director	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	Vice-President and co-founder of MiCasa Rentals Inc., a privately owned oilfield wellsite trailer rental company since 1993. Mr. Schultz is also a director of International Tech Corp.	January 9, 2003
J. Ronald Woods(1)(3) Toronto, Ontario	Director	President, 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.
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, CA 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 Ltd., 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 (as 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 Corporate Governance Committee.

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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.

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, 2003.

	Compensation		Securities Under Option(1)			Common Shares Owned
Name and Position	Salary	Other(2)	Number of	Exercise	Expiry
with Company	(Cdn$)	(Cdn$)	Options	Price	Date	Number	% Owned
Harold V. Pedersen	$43,130	$300	60,000	$0.81	Feb. 19, 2008	1,655,639	4.8
CEO and Director			150,000	$1.76	Aug. 26, 2008
Carrie McLauchlin, CA	$43,130	-	60,000	$0.81	Feb. 19, 2008	272,935	0.1
V.P. Finance & CFO			100,000	$1.76	Aug. 26, 2008
Remaining Directors	$268,461	$1,200	410,000	$0.81	Feb. 19, 2008	3,160,184(3)	9.1
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.
(2)	Other compensation includes director fees and bonuses. The underlying securities for all options are the Company's Common Shares and all options were obtained from grants by the Company.
(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 most recent 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 Company's Audit Committee is composed of Ronald L. Belsher, Hugh Mogensen, David Crevier and J. Ronald Woods (all of whom are considered independent directors as defined in the Toronto Stock Exchange Company Manual). This committee meets with the Company's financial officers and independent auditors to review and inquire into matters affecting financial reporting, the system of internal accounting and financial controls and procedures, and the audit procedures and audit plans. The Audit Committee also recommends to the Board of Directors the auditors to be appointed, and reviews and recommends to the Board for approval the annual financial statements, the annual report and certain other documents required by regulatory authorities.

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Compensation Committee

The Compensation Committee is comprised of Messrs. Ron Belsher, Alain Lambert (each of whom are considered independent directors) and Harold Pedersen. Meetings of the committee are held periodically to review employee compensation policies and to consider the overall compensation to be paid by the Company to its senior officers. Mr. Pedersen does not vote with respect to compensation matters specifically related to him as President.

The Company's compensation philosophy is aimed at attracting and retaining quality and experienced people which is critical to the success of the Company. Currently the compensation program for employees of the Company is comprised of salary and benefits, and the Company's stock option plan. While no bonuses have been declared to date, it is possible that they be granted from time to time based upon individual performance and the financial performance of the Company overall.

The purpose of the Compensation Committee is to recognize and reward individual performance as well as to provide a competitive industry level of compensation, taking into consideration the individual's experience and performance together with the financial situation of the Company. The committee considers stock options a key component of executive compensation. Stock options align executive and shareholder interests by creating a direct link between compensation and the success of the Company.

D. Employees

At December 31, 2003, the Company had 14 full-time employees at its Calgary based head office and 1 field contract operator. The head office employees' main categories of activity were as follows: 3 performed administrative functions, 4 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 labor union. The Company occasionally hires hourly employees on an "as needed" project basis.

E. Share Ownership

See Item 6.B

The following table outlines the stock options and Common Shares held by the directors and management of the Company as at June 21, 2004.

Name and Position	Number of
with the Company	Stock Options	Common Shares Owned
Harold V. Pedersen CEO and Director	210,000	1,753,339 or 5.03% of the issued and outstanding Common Shares
Carrie McLauchlin, C.A. V.P. Finance and CFO	160,000	272,935 or 0.08% of the issued and outstanding Common Shares
Remaining directors and officers	1,560,000	3,190,884 or 9.16% of the issued and outstanding Common Shares

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Stock Option Plan

The Company's stock option plan (the "Plan") permits the granting of options to purchase Common Shares to officers, directors and employees of, and key consultants to, the Company. Currently, a maximum of 3.3 million Common Shares may be reserved for issuance pursuant to the Plan. Since its adoption in February 2003, approximately 2,740,000 options have been granted (net of cancelled options) under the Plan, representing approximately 7.8% of the currently issued and outstanding Common Shares, leaving 565,395 options available for grant. As at June 21,2004,there were options to purchase 2,712,000 Common Shares outstanding under the Plan.

The Plan also provides that:

1.	any options granted pursuant to the Plan shall expire not later than 5 years after the date of grant;
2.	any options granted pursuant to the Plan shall be non-assignable;
3.	the exercise price of any options granted pursuant to the Plan shall not be lower than the market price of the Common Shares on the date of the grant, where the "market price" is defined as the closing trading price of the Common Shares on the Toronto Stock Exchange on the day immediately prior to the date of the grant;
4.	all options vest as to one-third on the first anniversary of the date of grant and on each successive anniversary until fully vested;
5.	the number of Common Shares issuable pursuant to the Plan to any one person shall not exceed 5% of the outstanding Common Shares; and
6.	the number of Common Shares reserved for issuance, or issuable within one year, pursuant to the Plan to insiders shall not exceed 10% of the outstanding Common Shares and the number of Common Shares issuable within one year pursuant to the Plan to any one insider and such insider's associates shall not exceed 5% of the outstanding Common Shares.

ITEM 7MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

 A.  Major Shareholders

To the knowledge of the management of the Company, no shareholder as at June 21, 2004 beneficially owns more than five percent (5%) of any class of the Company's voting securities except for Harold V. Pedersen, Chief Executive Officer of the Company (see Item 6B above).

At June 21, 2004, 3,226,426 Common Shares were held by 69 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.

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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;
(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.

ITEM 8FINANCIAL INFORMATION

Luke's Financial Statements are stated in Canadian dollars (Cdn.$) and are prepared in accordance with Canadian GAAP with 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, 2003 and January 9, 2003 and the audited statements of earnings, retained earnings and cash flows and related notes for 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.

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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 9THE OFFER AND LISTING

Trading Information

Fiscal Year:		2003
High	$	2.65
Low	$	1.35
Quarterly:		Q1/03	Q2/03	Q3/03	Q4/03	Q1/04
High		2.05	2.65	2.20	1.98	2.33
Low		1.35	1.86	1.65	1.71	2.00
Last 6 months:		May/04	Apr/04	Mar/04	Feb/04	Jan/04	Dec/03
High		2.30	2.34	2.31	2.33	2.25	1.90
Low		2.07	2.05	2.08	2.00	1.76	1.74

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

ITEM 10ADDITIONAL 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

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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.

Directors' 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.

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(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

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.

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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 signe d the requisition may call the meeting. The directors of a corporation may at any time call a special meeting of shareholders.

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 t he 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

40

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;
(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 prov ided 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.

41

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 Direct or 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.

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

42

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.

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.

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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.

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 securi ty 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. 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.

44

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 (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, 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.

45

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 generally will be “passive income” or “financial services 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 gai n 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 tha t 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.

46

Passive income also includes the excess of gains over losses from some commodities transactions, including some transactions involving oil and gas. Gains from commodities transactions, however, 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 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.

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. We also believe we will not be a passive foreign investment company in 2004, 2005 or subsequent years. We note, ho wever, 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 2004 or 2005, then it will not qualify for the start-up exception and will be a passive foreign investment company for 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, 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 ma y 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.

F.  Dividends and Paying Agents

Not Applicable.

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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.

I.  Subsidiary Information

Not Applicable.

ITEM 11QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

At December 31, 2003 the Company had no derivative financial instruments.

ITEM 12DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES

Not Applicable.

PART II

ITEM 13DEFAULTS, 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 14MATERIAL 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.

ITEM 15CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2003, the Company’s Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of Luke's disclosure controls and procedures. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that as of the end of the year, the

48

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

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 does not have a written Code of Ethics, as it is not required to under applicable corporate and securities laws in Canada. However, the Company and management are committed to conducting business, and do conduct business, in an ethical manner.

C.  Principal Accountant Fees and Services

Services Provided in 2003

AUDIT FEES
Audit of financial statements of the Company for fiscal 2003	$	15,000
Reviews of interim financial statements of the Company for Q1-Q3 2003and other meetings		9,000
Procedures related to the 14,872,758 special warrants issue		6,000
AUDIT AND OTHER AUDIT-RELATED FEES - TOTAL		30,000
TAX FEES
Services relating to acquisition strategies and compliance tax filing		6,200
FEES - TOTAL	$	36,200*

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

D.  Exemptions from the Listing Standards for Audit Committees

Not applicable.

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

The Company and its affiliates have not purchased any equity securities

ITEM 17FINANCIAL STATEMENTS

The following financial statements are attached and incorporated herein:

·	Auditors' Report dated March 8, 2004.	F-1
·	Balance Sheets as at December 31, 2003 and January 9, 2003.	F-2
·	Statement of Earnings and Retained Earnings for the Period Ended December 31, 2003.	F-3
·	Statement of Cash Flow for the Period Ended December 31, 2003.	F-4
·	Notes to Financial Statements for the Period Ended December 31, 2003.	F-5
·	Auditors' Report dated January 20, 2004.	F-6
·	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-8
·	Unaudited pro forma statements of earnings for the years ended December 31, 2003 and 2002	F-9

ITEM 18FINANCIAL STATEMENTS

See Item 17.

ITEM 19EXHIBITS

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/ Mary C. Blue
	Name: Mary C. Blue
	Title: President & Chief Operating Officer

Date:June 24, 2004

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Financial Statements of

LUKE ENERGY LTD.

Period ended December 31, 2003

REPORT OF INDEPENDENT PUBLIC ACCOUNTING FIRM

The Board of Directors
Luke Energy Ltd.

We have audited the accompanying balance sheets of Luke Energy Ltd. as at December 31, 2003 and January 9, 2003 and the related statement of earnings and retained earnings and cash flows for 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 consolidated financial statements based on our audits.

We conducted our audits in accordance with 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, the financial statements referred to above present fairly, in all material respects, the financial position of Luke Energy Ltd. as at December 31, 2003 and January 9, 2003, and the results of its operations and its cash flows for the period from January 9, 2003 to December 31, 2003 in accordance with Canadian generally accepted accounting principles.

Canadian generally accepted accounting principles 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 to the financial statements.

(Signed) “KPMG LLP”

Chartered Accountants

Calgary, Canada
March 8, 2004

LUKE ENERGY LTD.

Balance Sheets

		December 31,		January 9,
		2003		2003
Assets
Current assets:
Cash and term deposits	$	36,699,571	$	100
Receivables		529,815		–
		37,229,386		100
Capital assets (note 4)		7,998,257		–
	$	45,227,643	$	100
Liabilities and Shareholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities	$	2,203,148	$	–
Future taxes (note 9)		98,850		–
Asset retirement obligations (note 6)		110,930		–
Shareholders’ equity:
Share capital (note 7)		42,223,171		100
Contributed surplus		7,618		–
Retained earnings		583,926		–
		42,814,715		100
	$	45,227,643	$	100

See accompanying notes to financial statements.

On behalf of the Board:

	Director
Harold V. Pedersen
	Director
Mary C. Blue

LUKE ENERGY LTD.

Statement of Earnings and Retained Earnings

Period ended December 31, 31, 2003

Revenue:
Oil and gas production	$	1,715,620
Royalties		(434,687	)
Gain on sale of marketable securities		629,575
Interest		953,464
		2,863,972
Expenses:
Operating		262,754
General and administrative		1,134,408
Interest		2,680
Depletion, depreciation and accretion		493,404
		1,893,246
Earnings before taxes		970,726
Taxes (note 9):
Current		96,800
Future		290,000
		386,800
Earnings and retained earnings, end of period	$	583,926
Weighted average number of common shares outstanding (note 8)		29,759,428
Earnings per share – basic and diluted	$	0.02

See accompanying notes to financial statements.

LUKE ENERGY LTD.

Statement of Cash Flows

Period ended December 31 2003

Cash provided by (used in):
Operating:
Earnings for the period	$	583,926
Items not affecting cash:
Depletion and depreciation and accretion		493,404
Future taxes		290,000
Stock based compensation expense		7,618
Cash flow from operations		1,374,948
Change in non-cash working capital (note 10)		45,959
		1,420,907
Financing:
Common shares issued (note 7)		38,486,155
Initial common shares redeemed for cash		(100	)
		38,486,055
Investing:
Additions to capital assets		(4,834,865	)
Change in non-cash working capital (note 10)		1,627,374
		(3,207,491	)
Increase in cash		36,699,471
Cash position, beginning of period		100
Cash position, end of period	$	36,699,571

Cash position includes cash and term deposits.

See accompanying notes to financial statements.

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 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 of 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 booking of the site restoration provision 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
Site restoration		(62,250	)
	$	4,174,415
Consideration:
Issuance of 6,581,364 common shares	$	4,174,415

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

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. 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.
	(a)	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 per cent or more.
	(b)	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.

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

(c)	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 or 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. Any excess carrying value of the Company’s future cash flows would be recorded as a permanent impairment.
(d)	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 estimated 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. Any difference between the actual costs incurred and the amount of the liability recorded is recognized as a gain or loss in the Company’s earnings in the period the costs are incurred.
(e)	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.
(f)	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.

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

(g)	Stock-based compensation plans:
	The Company has a stock-based compensation plan as described in Note 7. The Company uses the intrinsic value method of accounting for its stock based compensation plan. Consideration paid by employees or directors on the exercise of stock options under the employee stock option plan are recorded as share capital. The Company does not recognize compensation expense on the issuance of stock options to employees and directors because the exercise price equals the market price on the day of the grant. The Company does apply the fair value method to stock options granted to non-employees resulting in recognition of compensation expense recorded to general and administrative costs with a corresponding amount to contributed surplus. The Black-Scholes option pricing model is used to estimate fair value. The Company discloses the pro forma effect of accounting for those stock option awards under the fair value method.
(h)	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 substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse.
(i)	Foreign currency translation:
	Amounts denominated in foreign currencies are translated into Canadian dollars at the year-end exchange rates. Gains or losses on translation are included in earnings.
(j)	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.
(k)	Hedging:
	The Company may use certain financial instruments to manage its exposure to commodity price and foreign exchange. The Company does not use these instruments for speculative purposes. Gains and losses on these transactions are reported as adjustments to revenue when related production is sold.

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

3.	Changes in accounting policies:
	In December 2003, the Company adopted AcG -16 “Oil and Gas Accounting – Full Cost”, the new guideline issued by the Canadian Institute of Chartered Accountants replaces AcG-5 “Full cost Accounting in the Oil and Gas Industry”.
	Under AcG-5, future net revenues for ceiling test purposes were based on proved reserves and were not discounted. Estimated future general and administrative costs and financing charges associated with the future net revenues were deducted in arriving at the “ceiling”.
	There were no changes to earnings, capital assets or any other reported amounts in the financial statements as a result of early adoption.
4.	Capital assets:

				Accumulated		Net book
		Cost		depreciation		value
Petroleum and natural gas properties,including well equipment	$	8,311,208	$	463,000	$	,848,208
Office furniture and equipment		175,983		25,934		150,049
	$	8,487,191	$	488,934	$	7,998,257

At December 31, 2003, costs of $2,817,099 related to unproven properties have been excluded from the depletion calculation. In 2003, the Company capitalized $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 $98,044, net of accumulated depletion, relating to the asset retirement obligation.

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

The Company performed a ceiling test calculation at December 31, 2003 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, 2003. The calculation was based on the independent engineering evaluation (escalated price case). The future pricing assumptions used in the engineering evaluation are as follows:

	WTI Oil	Foreign	AECO Gas
Year	($US/bbl)	Exchange Rate	($Cdn/mmbtu)
2004	29.00	0.75	5.85
2005	26.00	0.75	5.15
2006-2014	25.00	0.75	5.00
2015+	+1.5%/yr		+1.5%/yr

5.	Credit facility:
	The Company has a $2 million production loan facility available with a major Canadian bank. Pursuant to the terms of the agreement, any amounts owing will revolve until June 30, 2004 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. Loans under the facility may be made by way of prime based loans. A standby fee of 0.375 percent 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 1.0 percent from those during the revolving phase.
	The facility is secured by a first floating charge demand debenture over all of the Company’s assets.

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 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, 2003 the net present value of the total asset retirement obligation is estimated to be $106,460 based on a total future liability of $230,600. These payments are expected to be made over the next 30 years with the majority of costs incurred between 2011 and 2024. The Company’s adjusted risk free rate of five 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:

Carrying amount, beginning of the period	$	–
Recorded on acquisition of properties (note1)		62,250
Increase in liabilities, during the period		44,210
Settlement of liabilities during the period		–
Accretion expense		4,470
Carrying amount, end of period	$	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.

	Number of
	shares			Amount
Common Shares
Common shares issued and outstanding:
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, officersand 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
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

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

In September, the Company issued 1,775,000 common shares on a tax flow-through basis at $2.00 per share for proceeds of $3,550,000. Management and directors subscribed for 50% of the issue. Under the terms of the private placement the proceeds are to be expended on qualifying exploration drilling and seismic prior to December 31, 2004. At December 31, 2003, $2.7 million remains to be spent.

In March 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 the Officers, Directors and Employees Stock 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 have a term of five years to expiry and 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. At December 31, 2003, 2,665,000 options with exercise prices between $0.81 and $1.85 were outstanding and exercisable on various dates to 2008.

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

				Weighted
	Number of			average
	options			exercise price
Stock options, beginning of period	–			–
Granted	3,055,000		$	1.51
Exercised	–			–
Cancelled	(390,000	)	$	1.39
Stock options, end of period	2,665,000		$	1.52
Exercisable, end of period	–		$	–

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

The following table summarizes information about the stock options outstanding at December 31, 2003:

	Options outstanding at December 31, 2003
				Average		Weighted
				remaining		average
		Number		contractual		exercise
Range of exercise price		of options		life		price
Less than $1.900		675,000	$	4.14	$	0.81
Greater than $1.00		1,990,000		4.69		1.77
$0.81 to $1.85		2,665,000		4.55	$	1.52

The Company accounts for its stock-based compensation plans using the intrinsic-value method whereby no costs have been recognized in the financial statements for stock options granted to employees and directors. If the fair value method had been used, the Company’s earnings and earnings per share would approximate the following pro-forma amounts:

		Period ended
		December 31,
		2003
Fair value of options granted	$	1,879,895
Compensation expense	$	214,092
Earnings – as reported	$	583,926
Earnings – pro forma	$	369,834
Basic and diluted earnings per share – as reported	$	0.02
Basic and diluted loss per share – pro forma	$	0.01

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%.

During the period ended December 31, 2003 the Company recognized $7,618 of compensation expense (included in general and administrative expense) for stock options issued to non-employees.

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

8.	Per share amount:
	In computing diluted earnings per share, 581,480 shares were added to the weighted average number of common shares outstanding during the period ended December 31, 2003 for the dilutive effect of employee stock options and warrants. 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:

Oil and gas properties	$	990,450
Share issue costs		(891,600	)
	$	98,850

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:

Earnings before taxes	$	970,726
Combined federal and provincial tax rate		40.62	%
Computed “expected” tax	$	394,309
Increase (decrease) in taxes resulting from:
Non-deductible crown charges		29,066
Non-taxable portion of capital gain		(127,866	)
Non-deductible expenses		12,972
Effect of change in corporate tax rate		(50,558	)
Resource allowance		32,077
Large corporations tax		96,800
Reported income taxes	$	386,800

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

10. Change in non-cash working capital:

Receivables	$	(529,815	)
Accounts payable and accrued liabilities		2,203,148
	$	1,673,333
Non-cash working capital – operating	$	45,959
Non-cash working capital – investing		1,627,374
	$	1,673,333

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.	Supplemental cash flow information:
	Amounts actually paid during the period relating to interest expense and capital taxes are as follows:

		Period ended
		December 31,
		2003
Interest paid	$	2,680
Capital taxes paid	$	–

LUKE ENERGY LTD.

Notes to Financial Statements

Period ended December 31 2003

13.	Reconciliation to United States generally accepted accounting principles ("U.S. GAAP"):
	The Company follows accounting principles generally accepted in Canada which differ in certain respects from those applicable in the United States and from practices prescribed by the Securities and Exchange Commission (SEC). The significant differences in accounting principles and practices that could affect the reported earnings are as follows:
	(a)	The Company would be required to perform an 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. To date, application of the SEC prescribed test has not resulted in a write-down of capitalized costs.
	(b)	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. The estimated cost of the tax deductions renounced to shareholders has been reflected as a reduction of the stated value of the shares. The SEC requires that when the qualifying expenditures are incurred and 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.
	Reconciliation of the reported earnings as a result of the differences between Canada and the United States accounting principles for the period ended December 31, 2003 are as follows:

Earnings for the period, as reported	$	583,926
Estimated tax cost of the renunciation of tax benefits on expenditures		(1,329,000	)
Loss for the period in accordance with United States Accounting Principles	$	(745,074	)
Loss per share – basic and diluted	$	0.03

 

Statement of Revenue and Operating Expenses of the

Retained Assets to be transferred to

LUKE ENERGY LTD.

Three years ended December 31, 2002

Report of Independent 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

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

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 (“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.

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 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.

LUKE ENERGY LTD.

Pro Forma Statement of Earnings

Year ended December 31, 2003

(Unaudited)

(In thousands of dollars)

													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

LUKE ENERGY LTD.

Notes to Pro Forma Statement of Earnings, Page

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.

LUKE ENERGY LTD.

Notes to Pro Forma Statement of Earnings, Page

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 Lake 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.