Form 20-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

(Mark One)
o		REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934


x		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2003.


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to .

Commission File Number 0-29214

HAWKER RESOURCES INC.

(Exact name of Registrant as specified in its charter)

Alberta, Canada
(Jurisdiction of incorporation or organization)

700, 700 – 2^nd Street S.W.
Calgary, Alberta, T2P 2W1
(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

None.

Securities registered or to be registered pursuant to Section 12(g) of the Act:


Title of each class		Name of each exchange on which registered

Common Shares		Toronto Stock Exchange

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

Not Applicable.

As at December 31, 2003, the issuer’s authorized share capital consisted of an unlimited number of Common Shares, an unlimited number of Class A Shares and an unlimited number of preferred shares issuable in series, of which 35,997,200 Common Shares, 3,874,437 Class A Shares and no preferred shares were outstanding. As at June 30, 2004, the issuer’s authorized share capital consisted of an unlimited number of Common Shares and an unlimited number of preferred shares, issuable in series, of which 41,021,681 Common Shares and no preferred shares were outstanding.

GLOSSARY

In this document, unless the context otherwise requires, the following words and phrases have the meanings set forth below:

“2% Debenture” means a debenture of the Company issued as part of the Financing on April 3, 2003 in the principal amount of $8.40, bearing interest at the rate of 2% per annum from the date of issue payable on the earlier of the maturity date of December 31, 2003 and the date of surrender;

“Arrangement” means the arrangement involving BidCo and Southward pursuant to section 193 of the Business Corporations Act (Alberta) completed on April 30, 2003;

“ARTC” means Alberta Royalty Tax Credit;

“BidCo” means 1022971 Alberta Ltd., all of the outstanding shares of which were acquired by the Company for an aggregate consideration of $1.00 on March 31, 2003;

“Class A Share” means a class A share in the capital of the Company;

“Common Share” means a common share in the capital of the Company;

“Conversion” means the deemed exercise of all of the Warrants pursuant to which the former holders of the Warrants were issued, for each Warrant, 5 Common Shares and 9 Class A Shares upon the surrender of 5 Series V Shares, 9 Series W Shares and one 2% Debenture;

“Company” or “Hawker” means Hawker Resources Inc.;

“Equity Shares” means Common Shares and Class A Shares;

“Financing” means the financing completed by the Company on April 3, 2003 pursuant to which the Company issued 223,798 Common Shares and 430,493 Units for aggregate gross proceeds of approximately $3.7 million (which Units were converted to 6,026,902 Equity Shares pursuant to the Conversion);

“GLJ” means Gilbert Laustsen Jung Associates Limited, independent petroleum engineers, Calgary, Alberta;

“GLJ Report” means the report prepared by GLJ dated March 8, 2004, setting forth certain information relating to certain of the oil and gas reserves of the Company’s properties and the present value of the estimated future net reserves associated with such reserves;

“Gross” means Hawker’s working interest or royalty interest share of reserves or production, as the case may be, before the deduction of royalties and, with respect to land and wells, means the total number of acres or wells, as the case may be, in which Hawker has a working interest or a royalty interest;

“McDaniel” means McDaniel and Associates Consultants Ltd., independent oil and natural gas reservoir engineers;

“McDaniel Report” means the report prepared by McDaniel dated March 12, 2004, setting forth certain information relating to certain of the oil and gas reserves of the Company’s properties and the present value of the estimated future net reserves associated with such reserves;

“Myriad Company” means Myriad Energy Company, a wholly owned subsidiary of Pointwest;

“Net” means Hawker’s working interest share of production or reserves, as the case may be, after the deduction of royalties, and, with respect to land and wells, means Hawker’s working interest share therein;

“Optioned Properties” means all of the petroleum and natural gas rights and related assets of Southward other than those which are both west of the fifth meridian and in the Province of Alberta, as described under the heading “Item 4D – Information on the Company – Property, plant and equipment”;

“Pointwest” means Pointwest Energy Inc.;

“Purchase Option” means the option in favour of the Company to purchase an undivided interest of up to 49% in the Optioned Properties at a purchase price based on an ascribed price, as at May 1, 2003 and subject to adjustment, of $136,900,000 for a 100% interest in the Optioned Properties;

“Royalty Interest” means an interest in an oil and gas property consisting of a royalty granted in respect of production from the property;

“SEC” means the United States Securities and Exchange Commission;

“Series V Share” means a series V voting preferred share in the capital of the Company;

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“Series W Share” means a series W non-voting preferred share in the capital of the Company;

“Southward” means Southward Energy Ltd.;

“Statements of Revenues and Operating Expenses” means the statements of revenues and operating expenses relating to the proposed acquisition by the Company of an aggregate 50% undivided interest in the Optioned Properties audited by Deloitte & Touche LLP;

“TSX” means The Toronto Stock Exchange;

“Tax Act” means the Income Tax Act (Canada) and the regulations thereunder, as amended from time to time;

“Unit” means a Unit issued by the Company on April 3, 2003 pursuant to the Financing for a subscription price of $8.46787851 per Unit consisting of: (i) a 2% Debenture; (ii) a Warrant; (iii) 5 Series V Shares; and (iv) 9 Series W Shares;

“Warrant” means a series A warrant of the Company which entitled the holder thereof to purchase 5 Common Shares and 9 Class A Shares upon the surrender of 5 Series V Shares and 9 Series W Shares and either the surrender of a 2% Debenture or the payment of $8.40. Pursuant to the Conversion, all of the Warrants were deemed to be exercised;

“Working Interest” means the percentage undivided interest held by a party in an oil and gas property; and

“Zorin” means Zorin Exploration Ltd.

Unless otherwise indicated, references herein to “$” or “dollars” are to Canadian dollars.

ABBREVIATIONS


Crude Oil and Natural Gas Liquids		Natural Gas

Bbls	barrels	Mcf	thousand cubic feet
bbls/d	barrels per day	Mmcf	million cubic feet
Mbbls	thousand barrels	Bcf	billion cubic feet
Boe	barrels of oil equivalent of natural gas	mcf/d	thousand cubic feet per day
	and crude oil on the basis of 1 bbl of	mmcf/d	million cubic feet per day
	crude oil for 6 mcf of natural gas	GJ	gigajoules
boe/d	barrels of oil equivalent per day	GJ/d	gigajoules per day
Mboe	thousand boe
NGLs	natural gas liquids
Mmbtu	million British thermal units
Stb	standard stock tank barrel

CONVERSION

The following table sets forth certain standard conversions from Standard Imperial units to the International System of Units (or metric units).


To Convert From	To	Multiply By
mcf	Thousand cubic metres (“10³m³”)	0.0282
Thousand cubic metres	Mcf	35.494
bbls	Cubic metres (“m³”)	0.159
Cubic metres	Bbls	6.290
Feet	Metres	0.305
Metres	Feet	3.281
Miles	Kilometres	1.609
Kilometres	Miles	0.621
Acres	Hectares	0.405
Hectares	Acres	2.471

FORWARD-LOOKING STATEMENTS

Certain statements contained in this document constitute forward-looking statements. When used in this document, the words “may”, “would”, “could”, “will”, “intend”, “plan”, “anticipate”, “believe”, “seek”, “propose”, “estimate”, “expect”, and similar expressions, as they relate to the Company, are intended to identify forward-looking statements. Such statements reflect the Company’s current views with respect to future events and are subject to certain risks, uncertainties and assumptions. Many factors could cause the Company’s actual results, performance or achievements to vary from those described in this document. Should one or more of these risks or uncertainties materialize, or should assumptions

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underlying forward-looking statements prove incorrect, actual results may vary materially from those described in this document as intended, planned, anticipated, believed, estimated or expected. The Company does not intend, and does not assume any obligation, to update these forward-looking statements.

In particular, this document contains forward-looking statements pertaining to the following:

• the quantity of the Company’s reserves;

• oil and natural gas production levels;

• capital expenditure programs;

• projections of market prices and costs;

• supply and demand for oil and natural gas;

• expectations regarding the Company’s ability to raise capital and to continually add to reserves through acquisitions and development; and

• treatment under governmental regulatory regimes.

The Company’s actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this document:

• volatility in market prices for oil and natural gas;

• liabilities and risks inherent in oil and gas operations;

• uncertainties for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

• incorrect assessments of the value of acquisitions; and

• geological, technical, drilling and processing problems.

PART I

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

A. Selected financial data.

The following selected financial data, for the periods indicated, has been derived from the Company’s financial statements, which are included elsewhere herein, and was prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”). Canadian GAAP differs in certain respects from U.S. generally accepted accounting principles (“U.S. GAAP”). For a description of the material differences between Canadian GAAP and U.S. GAAP with respect to the Company’s financial statements, see note 18 to the financial statements contained herein. The following selected financial data is qualified in its entirety by, and should be read in conjunction with the financial statements and the notes thereto appearing elsewhere in this annual report and “Item 5. Operating and Financial Review and Prospects”. The historical results below are not necessarily indicative of the results to be expected for any future period.

The Company’s financial statements are stated in Canadian Dollars (“CDN$” or “$”).

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Selected Consolidated Financial Information
Consolidated Statement of Earnings and Deficit Data


	Pro Forma
	Nine Months Ended September 30, 2003			Year Ended December 31,
	(unaudited)			2003			2002			2001			2000			1999
				(in thousands, except per share amounts)
Earnings Statement Data
Revenues:
Oil and natural gas sales	$	70,104		$	17,582		$	—		$	—		$	—		$	—
Royalties, net		(17,854	)		(4,205	)		—			—			—			—
Interest and other income		450			565			139			729			1,513			694

Net revenues		52,700			13,942			139			729			1,513			694

Expenses:
Production		6,725			2,028			—			—			—			—
Research and development		—			—			—			9,255			7,889			11,248
General and administrative.		3,099			4,590			1,621			7,106			3,648			3,934
Interest		1,707			679			71			787			1,176			1,434
Depletion, depreciation and asset write-downs		25,968			8,933			26			9,655			1,404			687
Site restoration		550			—			—			—			—			—

Total expenses		38,049			16,230			1,718			26,803			14,117			17,303

		14,651			(2,288	)		(1,579	)		(26,074	)		(12,604	)		(16,609	)
Earnings (loss) before the following:
Lease abandonment expense		(322	)		(502	)		—			—			—			—
Operating costs and write-downs associated with assets held For Sale		(179	)		(190	)		(7,408	)		—			—			—
Alberta Heritage Foundation grant settlement		368			368			—			—			—			—
Gain on sale and distribution of Oncolytics shares		—			—			13,067			3,004			—			—
Share of loss from equity investment in Oncolytics		—			—			(314	)		(1,831	)		(691	)		—
Gain on dilution of investment in Oncolytics		—			—			—			357			4,933			1,236
Gain on sale of INH		—			—			—			—			568			—

Earnings (loss) before tax		14,518			(2,612	)		3,766			(24,544	)		(7,794	)		(15,373	)
Non-controlling interest		—			—			—			—			—			291
Income tax recovery (expense)		(239	)		4,926			—			1,556			(95	)		—

Net earnings (loss), Canadian GAAP	$	14,279		$	2,314		$	3,766		$	(22,988	)	$	(7,889	)	$	(15,082	)

Net earnings (loss), U.S. GAAP				$	(17,820	)	$	9,511		$	(20,367	)	$	(12,802	)	$	(18,535	)

Basic and diluted net earnings (loss) per share
Canadian GAAP				$	0.14		$	0.76		$	(4.64	)	$	(1.63	)	$	(4.43	)
U.S. GAAP				$	(1.04	)	$	1.92		$	(4.11	)	$	(2.65	)	$	(5.45	)
Weighted average number of common and Class A shares outstanding					17,123,542			4,959,937			4,955,199			4,828,812			3,400,342

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Selected Financial Information
Balance Sheet Data


	Pro Forma
	Nine Months Ended September 30, 2003			Year Ended December 31,
	(unaudited)			2003			2002			2001			2000			1999
				(in thousands, except per share amounts)
Current assets	$	15,391		$	15,922		$	492		$	6,056		$	19,137		$	12,031
Investments		—			—			—			5,745			7,695			—
Assets held for sale		2,190			2,190			3,500			—			—			—
Property and equipment		156,976			166,990			23			10,783			19,494			21,483

	$	174,557		$	185,102		$	4,015		$	22,584		$	46,326		$	33,514

Current liabilities	$	28,163		$	33,750		$	80		$	10,781		$	4,195		$	4,143
Other liabilities		1,060			3,746			387			387			1,943			2,778
Bank loan		40,406			44,149			—			—			5,910			8,276

Total liabilities		69,629			81,645			467			11,168			12,048			15,197

Shareholders’ equity
Share capital		115,289			110,204			12,741			84,271			84,145			58,834
Contributed surplus		—			132			—			—			—			—
Retained earnings (deficit)		(10,361	)		(6,879	)		(9,193	)		(72,855	)		(49,867	)		(40,517	)

Total		104,928			103,457			3,548			11,416			34,278			18,317

	$	174,557		$	185,102		$	4,015		$	22,584		$	46,326		$	33,514

Shareholders’ equity- U.S. GAAP				$	102,502		$	3,548		$	5,671		$	25,912		$	14,864

Dividends

The Company has neither declared nor paid dividends on any of its outstanding common shares, and does not intend to do so in the foreseeable future. The Company intends to retain any future earnings to finance the expansion of its business. Any future determination to pay dividends will be at the discretion of the Board of Directors of the Company and will be dependent upon the Company’s earnings, capital requirements and financial position, as well as any other factors deemed relevant by the Board of Directors.

Currency and Exchange Rates

Canadian Dollar Value for $1.00 U.S. (as published by the Federal Reserve Bank of New York):

On June 30, 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 $1.00 U.S. = $ 1.3407 Canadian.

All exchange rate calculations 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.

Year Ended December 31, 1999

1.4858

Year Ended December 31, 2000

1.4855

Year Ended December 31, 2001

1.5487

Year Ended December 31, 2002

1.5704

Year Ended December 31, 2003

1.4013

High Rate

Low Rate

January 2004

1.3340

1.2690

February 2004

1,3442

1.3108

March 2004

1.3480

1.3080

April 2004

1.3711

1.3095

May 2004

1.3970

1.3580

June 2004

1.3772

1.3407

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

B. Capitalization and indebtedness.

Not applicable.

C. Reasons for the offer and use of proceeds.

Not applicable.

D. Risk factors

An investment in the Company’s securities should be considered highly speculative due to the Company’s recent change of business and the nature of such business as well as the Company’s present stage of development. A prospective investor should consider carefully the risk factors set out below.

Exploration, Development and Production Risks

Oil and gas operations involve many risks which even a combination of experience and 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 reserves are exploited. A future increase in the Company’s reserves will depend not only upon the Company’s ability to explore and develop any properties it may have, but also on its ability to select and acquire suitable producing properties. No assurance can be given that the Company will be able to continue to locate satisfactory properties for acquisition or to participate in other ventures or be able to identify and reach agreement with suitable partners. Moreover, if such acquisitions or partners are identified, the Company may determine that current markets, terms of acquisition and participation or pricing conditions make any such opportunities uneconomic. There is no assurance that commercial quantities of oil and natural gas will be discovered or acquired by the Company.

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

In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires and spills. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on future results of operations, liquidity and financial condition.

Insurance

The Company’s involvement in the exploration for and development of oil and 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 such 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.

Prices, Markets and Marketing of Crude Oil and Natural Gas

Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond the control of the Company. World prices for oil and natural gas have fluctuated widely in recent

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years. Any material decline in prices could result in a reduction of net production revenue. Certain wells or other projects may become uneconomic as a result of a decline in world oil prices and natural gas prices, leading to a reduction in the volume of the Company’s oil and gas reserves. The Company might also elect not to produce from certain wells at lower prices. All of these factors could result in a material decrease in the Company’s future net production revenue, causing a reduction in its oil and gas acquisition and development activities. In addition, bank borrowings available to the Company are in part determined by the borrowing base of the Company. A sustained material decline in prices from historical average prices could limit or reduce the Company’s borrowing base, thereby reducing the debt financing available to the Company, and could require that a portion of any existing debt financing of the Company be repaid.

The marketability and price of oil and natural gas which may be acquired or discovered by the Company will be affected by numerous factors beyond its control. The Company may be affected by the differential between the price paid by refiners for light quality oil and the grades of oil produced by the Company. The ability of the Company to market its natural gas may depend upon its ability to acquire space on pipelines which deliver natural gas to commercial markets. The Company may also likely be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing facilities and related to operational problems with such pipelines and facilities and 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.

Substantial Capital Requirements; Liquidity

The Company anticipates that it will make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas reserves in the future. 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. Moreover, future activities may require the Company to alter its capitalization significantly. The inability of the Company to access sufficient capital for its operations could have a material adverse effect on the Company’s financial condition, results of operations or prospects.

Competition

The Company will compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than the Company. The Company’s competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators. The Company’s ability to increase reserves in the future will depend not only on its ability to explore and develop the properties to be acquired upon the exercise of the Purchase Option, 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.

The oil and gas industry is highly competitive. The Company’s competitors for the acquisition, exploration, production and development of oil and natural gas properties, and for capital to finance such activities, include companies that have greater financial and personnel resources available to them than the Company.

The Company’s ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with its future industry partners and joint operators and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.

Environmental Risks

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 international conventions and state and municipal 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 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 potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of

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production, development or exploration activities or otherwise adversely affect the Company’s financial condition, results of operations or prospects.

Reserves Replacement

The Company’s future oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on the Company successfully acquiring or discovering new 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 the Company’s ability to develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. There can be no assurance that the Company’s future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas.

Reliance on Operators and Key Employees

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 largely be unable to direct or control the activities of the operators. In addition, the success of the Company will be largely dependent upon the performance of its management and key employees. The Company does not have any key man insurance policies, and therefore there is a risk that the death or departure of any member of management or any key employee could have a material adverse effect on the Company. In assessing the risk of an investment in the Common Shares, potential investors should recognize that they are relying on the ability and integrity of the management of the Company.

Corporate Matters

To date, the Company has not paid any dividends on its outstanding Common Shares and does not anticipate the payment of any dividends on its Common Shares in the near future.

Certain of the directors and officers of the Company are also directors and officers of other oil and gas companies involved in natural resource exploration and development, and conflicts of interest may arise between their duties as officers and directors of the Company and as officers and directors of such other companies. Such conflicts must be disclosed in accordance with, and are subject to such other procedures and remedies as apply under, the Business Corporations Act (Alberta).

Permits and Licenses

The operations of the Company may require licenses and permits 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 of its projects.

Additional Funding Requirements

The Company’s cash flow from its properties may not be sufficient to fund its ongoing activities and implement its business plan. 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 future revenues from its future reserves decrease as a result of lower oil and natural gas prices or otherwise, it will 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 available to meet these requirements or be available on favourable terms.

Issuance of Debt

The Company’s activities may be financed partially or wholly with debt, which may increase the Company’s debt levels above industry standards. 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.

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Availability of Drilling Equipment and Access Restrictions

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 equipment or access restrictions may affect the availability of such equipment to the Company and may delay exploration and development activities.

Title Defects

Although title reviews will generally be conducted prior to the purchase of most oil and natural gas producing properties or the commencement of drilling wells, such reviews may not discover unforeseen title defects that could adversely affect the Company’s title to the property or entitlement to revenue from the property.

Uncertainty of Reserve Information

There are numerous uncertainties inherent in estimating quantities of reserves and cash flows to be derived from exploration and production activities, including many factors that are beyond the control of the Company. The reserve and cash flow information set forth in this annual report represent estimates only. The reserves and estimated future net cash flow from the Company’s properties have been independently evaluated effective December 31, 2003. These evaluations include a number of assumptions relating to factors such as initial production rates, production decline rates, ultimate recovery of reserves, timing and amount of capital expenditures, marketability of production, future prices of oil and natural gas, operating costs and royalties and other government levies that may be imposed over the producing life of the reserves. These assumptions were based on price forecasts in use at the date the relevant evaluations were prepared and many of these assumptions are subject to change and are beyond the control of the Company. Actual production and cash flows derived therefrom will vary from these evaluations, and such variations could be material. The foregoing evaluations are based in part on the assumed success of 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 activities do not achieve the level of success assumed in the evaluations.

Canadian and United States practices differ in reporting reserves and production

The Company reports its production and reserve quantities in accordance with Canadian practices. These practices are different from the practices used to report production and to estimate reserves in reports and other materials filed with the SEC by companies in the United States.

The Company includes additional information with respect to production and reserves which is either not generally included or prohibited under rules of the SEC and practices in the United States. The Company follows the Canadian practice of reporting gross production and reserve volumes; however, the Company also follows the United States practice of separately reporting these volumes on a net basis (after the deduction of royalties and similar payments). In addition, the Company also follows the Canadian practice of using forecast prices and costs when it estimates its reserves; however, the Company also separately estimates its reserves using prices and costs held constant in accordance with the Canadian reserve reporting requirements. These requirements are similar to the constant pricing reserve methodology utilized in the United States.

The Company also includes in this annual report estimates of probable reserves along with estimates of proved reserves. The SEC generally prohibits the inclusion of estimates of probable reserves in filings made with it; however, the Company is permitted under the SEC rules to include such information in this annual report as such information is required to be disclosed under Canadian disclosure requirements.

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 nation-wide 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 will emit 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 proposed in Alberta’s Bill 32: Climate Change and Emissions Management Act, may require the reduction of emissions or emissions intensity from the Company’s operations and facilities. The direct or indirect costs of these regulations may adversely affect the business of the Company.

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Government Regulation and Taxation

Oil and gas operations are subject to extensive Canadian federal, provincial and local laws and regulations governing exploration, development, transportation, production, exports, labour standards, occupational health, waste disposal, protection and redemption of the environment, mine safety, hazardous materials, toxic substances, taxation and other matters. It is believed that the Company is in substantial compliance with all applicable laws and regulations. Amendments to current laws and regulations governing oil and gas operations and the more stringent implementation thereof are actively considered form time to time and the implementation thereof could have a material adverse impact on the Company. In addition, taxation laws and regulations as well as the current administrative practices of both the federal and provincial tax authorities may be amended or construed in such a way that is detrimental to the Company or its activities.

Item 4. Information on the Company

A. History and development of the Company.

The Company

The Company was incorporated as 599386 Alberta Ltd. under the Business Corporations Act (Alberta) on February 14, 1994 and changed its name to SYNSORB Biotech Inc. on March 31, 1994. Effective May 8, 2002: (i) each former holder of common shares received one new common share for each eight cancelled common shares they previously held; (ii) the stated capital of the Company was reduced in respect of the common shares of the Company by $59,896,000; and (iii) 4,000,235 common shares of Oncolytics Biotech Inc. held by the Company were distributed to its shareholders. By articles of amendment filed on April 3, 2003, the name of the Company was changed to Hawker Resources Inc. and a new class of non-voting equity shares was created. On December 30, 2003, each of Pointwest and its wholly-owned subsidiary, Myriad Company, and the Company amalgamated pursuant to the provisions of the Business Corporations Act (Alberta) under the name Hawker Resources Inc. On December 31, 2003, 1053639 Alberta Ltd., a wholly-owned subsidiary of the Company, and the Company amalgamated pursuant to the provisions of the Business Corporations Act (Alberta) under the name Hawker Resources Inc. On March 17, 2004, Zorin was wound-up into the Company, pursuant to the provisions of the Business Corporations Act (Alberta).

The head office of the Company is located at 700, 700 – 2^nd Street S.W., Calgary, Alberta, T2P 2W1, and its telephone number at that address is (403) 261-6883. The registered office of the Company is located at 4500, 855 – 2^nd Street S.W., Calgary, Alberta, T2P 4K7.

History

Prior to December 10, 2001, the Company was a biotechnology company focusing primarily on the discovery and development of pharmaceutical products for gastroenteric diseases. On that date, the Company announced that it was terminating the clinical trials of its remaining product and would consider future strategic alternatives.

Over the course of the fiscal year ended December 31, 2002, the Company divested itself of its position in Oncolytics Biotech Inc. by distributing 4,000,235 of such shares to its shareholders and by selling 2,255,565 of such shares through the TSX for aggregate gross proceeds of $6,898,000. During that period, the Company completed staff reductions and the winding-down of its clinical trials and continued to evaluate strategic alternatives. The Company held discussions with several industry parties in an attempt to reach a transaction with another pharmaceutical entity that would make use of the Company’s technology and its specialized manufacturing plant and equipment. These discussions did not lead to the Company receiving any acceptable proposal for such a transaction.

On October 30, 2002, the Company retained Network Capital Inc. as its financial advisor to seek a transaction to maximize value for shareholders, including pursuing transactions that would substantially reorganize the business of the Company.

On November 26, 2002, Southward announced a shareholder value maximization process, established an independent committee to oversee the process and retained a financial advisor. The process initiated by Southward required that binding offers be submitted by interested parties on or prior to March 3, 2003.

In late December 2002, the Company approached an investor group led by David Tuer with respect to the transformation of the Company from a pharmaceutical research company into an oil and gas enterprise and the completion of the Financing. On January 6, 2003, the transformation of the Company to an oil and gas enterprise and the proposed Financing were announced, subject to obtaining shareholder approval, which was to be sought at the annual and special meeting of the Company on April 3, 2003.

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In January 2003, the Company sold its manufacturing equipment for approximately $940,000 in net proceeds and in February 2003, the Company granted a third party an exclusive license to certain of its patents relating to toxin binding sugars for net proceeds of US $240,000. The Company is continuing to attempt to sell its manufacturing facility and related land.

In early March 2003, BidCo entered into an agreement with a third party which provided, as amended, that in the event that BidCo was successful in purchasing all of the common shares of Southward, the third party would purchase all of the petroleum and natural gas rights and related assets of Southward, except for a 1% interest in the Optioned Properties and 100% of the seismic data relating to the Optioned Properties, for a purchase price of $164,631,000, of which $135,531,000 was allocated for internal purposes to a 99% interest in the Optioned Properties.

In mid-March 2003, the Purchase Option was granted which provided the right to purchase an undivided interest of up to 49% in the Optioned Properties at a purchase price, subject to adjustment, equal to $1,369,000 for each 1% undivided interest in the Optioned Properties acquired pursuant to the Purchase Option. The right to exercise the Purchase Option was conditional upon the completion of the sale of the Southward assets to the grantor of the option, which condition was satisfied on April 30, 2003. The Purchase Option provided that it could be assigned to the Company, but that it could not be assigned to any other party without the prior written consent of the grantor of the option.

On March 16, 2003, BidCo entered into an arrangement agreement with Southward which contemplated that, subject to the terms and conditions of the agreement, BidCo and Southward would implement the Arrangement. The Arrangement provided that: (i) shareholders of Southward would transfer all of the outstanding common shares to BidCo in consideration for $4.77 per share; and (ii) all of the outstanding options to acquire common shares of Southward would be terminated, and in consideration for such termination the former holders of the options would receive the difference between the exercise price of each of their options and $4.77, provided that if such amount was less than $0.10 in respect of any option, the former holder thereof would receive $0.10.

As a pre-condition to Bidco entering into the arrangement agreement, Southward agreed that, at the direction of Bidco, it would enter into fixed price forward sales contracts in respect of up to 12,875 GJ/d of gas production from the Southward Properties. On March 17, 2003, Southward entered into forward sales contracts in respect of an aggregate of 12,880 GJ/d for the balance of 2003 and the first quarter of 2004.

On March 31, 2003, the Company acquired the Purchase Option and all of the shares of BidCo for an aggregate consideration of $1.00.

At the annual and special meeting of the shareholders of the Company held on April 3, 2003 a new board of directors was elected, including the appointment of David Tuer, an experienced oil and gas senior executive, as the new Chairman of the Board and Chief Executive Officer of the Company, and the shareholders approved, among other things: (i) the Financing; (ii) the creation of the Class A Shares; and (iii) the name change to Hawker Resources Inc.

On April 3, 2003, the Company completed the Financing and issued 223,798 Common Shares and 430,493 Units for aggregate proceeds of approximately $3.7 million. The Units were converted into an aggregate of 6,026,902 Common Shares on May 29, 2003. During the period of March 13, 2003 to April 3, 2003, all outstanding in-the-money stock options were exercised, resulting in the issuance of an additional 275,000 Common Shares for aggregate proceeds of $192,000.

On April 28, 2003 the Arrangement was approved by the shareholders and option holders of Southward and was also approved by the Court of Queen’s Bench of Alberta. On April 30, 2003, the Arrangement was completed by Southward and BidCo in accordance with the arrangement agreement. Pursuant to the Arrangement, BidCo paid an aggregate of approximately $120 million to the shareholders and option holders of Southward and Southward became a wholly owned subsidiary of BidCo.

Concurrent with the completion of the Arrangement, Southward completed the sale of all of its oil and gas assets, with the exception of: (i) a 1% interest in the Optioned Properties; and (ii) 100% of the seismic data relating to the Optioned Properties, which were retained by Southward. Prior to the completion of the Arrangement, the Company granted a call option which gives the purchaser of the oil and gas assets of Southward the right to acquire from the Company a 99% interest in the seismic data in respect of the Optioned Properties, for a purchase price of $3,710,000 (the “Purchase Option”).

On May 30, 2003, pursuant to the Conversion, the securities which comprised the Units were converted into an aggregate of 6,026,902 Equity Shares immediately after a receipt was issued for the Company’s prospectus qualifying the issuance of up to $45,000,900 of Common Shares.

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On June 12, 2003, the Company completed a public offering of 14,286,000 Common Shares at a price of $3.15 per share for aggregate gross proceeds of approximately $45 million. Net proceeds from the offering were used to finance the acquisition of the Optioned Properties.

On June 30, 2003, the Company exercised the Purchase Option and, accordingly, acquired a 49% interest in the Optioned Properties, and also purchased the 1% undivided interest in the Optioned Properties. At this time, the non-cash working capital of Southward was conveyed to the Company.

All of the shares of 1022971 Alberta Ltd (including its wholly-owned subsidiary, Southward, and all other subsidiaries) were sold for nominal consideration by the Company to an independent third party on June 30, 2003.

On August 14, 2003, the Company acquired all of the shares of 1053638 Alberta Ltd. and 1053639 Alberta Ltd., seismic data companies, for an aggregate consideration equal to $1,500,000. On August 19, 2003, the Company subsequently sold all of the shares of 1053638 Alberta Ltd. for $300,000.

On December 5, 2003, the Company completed a private placement of 2,900,000 flow-through Common Shares at a price of $5.25 per share for gross proceeds of $15,225,000. The Company agreed to renounce to subscribers under this private placement “Canadian Exploration Expense” as defined in the Income Tax Act (Canada) (the “Tax Act”) in the aggregate amount of $15,225,000 with an effective date, for income tax purposes, of on or before December 31, 2003.

On December 30, 2003, the Company acquired all of the issued and outstanding common shares of Pointwest for an aggregate purchase price of approximately $88 million, inclusive of debt. Prior to such acquisition, Pointwest was an oil and natural gas exploration and production company based in Calgary, Alberta with an asset base within an area primarily in northeastern British Columbia.

Concurrent with the completion of the acquisition of Pointwest, the Company closed a short form prospectus equity financing of 11,200,000 Common Shares at a price of $4.05 per share for gross proceeds of $43,360,000. The net proceeds from this equity financing were used to partially finance the Company’s acquisition of all of the shares of Pointwest. The balance of the funds required to complete the acquisition were advanced to the Company under an expanded credit facility with the Canadian Imperial Bank of Commerce. Effective December 30, 2003, each of Pointwest and Myriad Company, its wholly-owned subsidiary, was amalgamated into the Company pursuant to the provisions of the Business Corporations Act (Alberta).

On March 17, 2004, the Company acquired all of the issued and outstanding common shares of Zorin for an aggregate purchase price of a cash payment of approximately $1.5 million and the issuance by the Company of 1,150,000 Common Shares. Prior to such acquisition, Zorin was a publicly-traded junior oil and natural gas exploration company based in Calgary, Alberta with activities in Alberta, Saskatchewan, Ontario and Ohio. Zorin’s average production for 2003 was approximately 218 bbls/d of oil and NGLs and 924 mcf/d of natural gas. The majority of the production from the properties in which Zorin has an interest are operated by Zorin.

The Company currently intends to continue the business carried on by Zorin in the Granlea, Alberta area and vigorously exploit and develop this property and properties adjacent to Granlea in which the Company has a working interest. The Company may, however, determine to sell all or any portion of remaining properties in which Zorin has an interest and may also choose to operate and exploit such properties in a manner different from that of Zorin. On March 17, 2004 Zorin was wound-up into the Company pursuant to the provisions of the Business Corporations Act (Alberta).

B. Business overview.

General Development of the Business

The Company is a publicly traded Canadian company listed on the TSX (symbol: HKR) engaged in the business of exploring for and developing oil and natural gas reserves in Western Canada and acquiring oil and natural gas properties. The Company intends to report the financial results of its oil and gas activities as one industry segment. For operational purposes, the Company intends to manage all of its oil and gas activities as one integrated unit.

Corporate Strategy

Vision - The Company’s primary ongoing business objective is to become a full cycle oil and gas company with a dual focus on exploration and development activities and on an active acquisition strategy, with a particular emphasis on natural gas opportunities.

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Drilling Program - Management intends to employ a “cheap deep” approach to exploration by implementing a high density drilling program with low cost options to look at deeper horizons, while continuing to seek out additional opportunities to add to the Company’s land base.

Responsible Fiscal Management - Approximately 50% of the Company’s anticipated cash flow will be directed towards the replacement of existing reserves, leaving a significant amount of cash flow available for a focused exploration program or to pay down debt. The Company strives to add value through its drilling and exploration activities and carefully manages its costs, thereby positioning itself to add to its inventory of opportunities and undeveloped land holdings.

Prudent Use of Equity – Management recognizes that, at this early stage of development, equity must be used sparingly, and it intends to rely heavily on operational revenues and debt financing to satisfy liquidity requirements. The Company will attempt to minimize the dilution that would be caused to existing shareholders if large amounts of equity were issued.

Business Strengths

Strength of Management – Mr. Tuer has over 28 years of petroleum engineering and management experience in Canada and internationally, including experience as President and Chief Executive Officer of one of Canada’s largest energy companies. Mr. Terry Schmidtke has over 24 years of operational experience in the areas of reservoir engineering, field operations, strategic planning and acquisitions and divestitures. Mr. Herring has over 22 years of accounting and oil and gas experience.

Experienced, Interested Board – The Company’s board of directors is comprised of individuals with broad backgrounds and demonstrated experience in creating shareholder value. In particular, Mr. Tuer, Mr. Ronald Mathison, Mr. Martin Lambert and Mr. Stan Grad have extensive industry and transactional experience. Several of the directors have significant financial stakes in the Company.

Focused Production Areas – The Company has high quality, tightly focused properties that management believes can be exploited through additional developmental drilling. The Company’s properties contain close to 100 geophysically and geologically defined locations, and include over 180,000 net acres of undeveloped land.

Emphasis on Gas – The Company’s early stage production will be 100% natural gas. As the Company expands, its portfolio of oil producing properties will increase, but the emphasis on natural gas will remain part of Hawker’s business plan.

Price Certainty Through Hedging – An integral part of the Company’s strategy in acquiring an interest in the Optioned Properties was the prior negotiation of the right to secure certain hedging arrangements in respect of a portion of the production from the properties. These forward sales contracts reduce the economic uncertainty of the acquisition of an interest in the Optioned Properties by providing certainty to the price for a material portion of Hawker’s 2003 and first quarter 2004 gas production.

Advantageous Tax Position – As at December 31, 2003, the Company has non-capital losses and unclaimed expenditures of approximately $ 18,035,000 and $ 6,787,000, respectively, that are available for application against future taxable income. The Company also has approximately $ 5,700,000 of unclaimed investment tax credits available to reduce future year’s income tax.

Geographic Markets and Revenues

During the fiscal year ended December 31, 2003, approximately 98% and 2% of the Company’s revenues were generated from Canadian and international customers, respectively. During the fiscal years ended December 31, 2002 and 2001, 100% of the Company’s revenues were generated from customers in Canada. During the fiscal year ended December 31, 2000, approximately 94% and 6% of the Company’s revenues were generated from Canadian and international customers, respectively. During the fiscal years ending December 31, 2002, 2001 and 2000, 100% of the revenues from the Optioned Properties were generated in Canada.

Seasonality

The Company expects to have seasonal impacts with regard to its exploration and development program. The Company expects to experience reduced activity in the second quarter of the fiscal year as limitations on the

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transportation of heavy equipment on municipal roads curtails the ability of drilling rigs and other oilfield equipment to get to and from well sites.

Commodity Price Volatility

Crude oil and natural gas prices are volatile and subject to a number of external factors. Prices are cyclical and fluctuate as a result of shifts in the balance between supply and demand for crude oil and natural gas, world and North American market forces, inventory and storage levels, OPEC policy, weather patterns and other factors. In early 2003, the industry initially saw a general strengthening of prices for both oil and natural gas. Currently, tight supply/demand balance has kept prices high for both crude oil and natural gas.

Crude oil is influenced by a world economy and OPEC’s ability to adjust supply to world demand. Recent success by OPEC and low North American crude stocks have kept crude oil prices high. However, the Company expects world prices of crude oil to decrease to historical average levels of approximately US $24 per barrel (WTI), but also expect continued global political factors to hold prices at those levels.

Natural gas prices are greatly influenced by market forces in North America. It is generally believed that natural gas has greater stability than crude oil in terms of short-term pricing as there is a shortage of natural gas production and natural gas storage levels are low. The Company expects natural gas prices to moderate somewhat through 2004, but expect the supply of North American natural gas to continue to be constrained by North American production decline rates.

Industry Consolidation and Competition

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

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

As occurred in 2002 and 2003, the strength of commodity prices resulted in significantly increased operating cash flows and has led to increased drilling activity. The Canadian Association of Oilwell Drilling Contractors forecasts a 9% decrease in industry drilling in 2004. Even with this predicted decrease, industry activity level will result in competition for oilfield goods and services and may cause drilling and operating costs to increase.

Provincial Royalties and Incentives

For crude oil, natural gas and related product production from federal or provincial Crown lands, the royalty regime is a significant factor in the profitability of such production operations. Royalties payable on production from lands other than Crown lands are determined by negotiations between the freehold mineral owner and the lessee, although production from such lands is also 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 the type of product being produced, well productivity, geographical location and field discovery date. From time to time the various provincial governments in western Canada have established incentive programs which have included royalty rate reductions, royalty holidays and tax credits for the purpose of encouraging oil and gas exploration and development. The trend in recent years has been for provincial governments to allow such programs to expire without renewal, and consequently few such programs are currently operative.

Crude oil and natural gas royalty holidays for specific wells and royalty reduction reduce the amount of Crown royalties paid by the Company to the provincial governments. In Alberta, the Alberta royalty tax credit program also provides a rebate, to certain eligible producers, on Alberta Crown royalties paid in respect of eligible producing properties. These incentives result in increased profitability from operations of the Company.

Trademarks and Intellectual Property Rights

There are no intellectual property rights, licenses or industrial, commercial or financial contracts that are material to the Company’s business or profitability.

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Competitive Conditions

The oil and gas industry is highly competitive. The Company will compete for reserve acquisitions, exploration leases, licences and concessions and skilled industry personnel with a substantial number of other oil and gas companies, many of which have significantly greater financial resources than the Company. The Company’s competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators. The Company’s ability to increase reserves in the future will depend not only on its ability to explore and develop its 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.

Government Regulation

The oil and natural gas industry is subject to extensive controls and regulation imposed by various levels of government. In Western Canada, the various provincial governments have legislation and regulations, which govern land tenure, royalties, production rates, environmental protection and the prevention of waste. The oil and natural gas industry is also subject to regulation and intervention by governments in such matters as the award of exploration and production rights, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields (including restrictions on production) and, possibly, expropriation or cancellation of contract rights. It is not expected that these controls and regulation will affect the operations of the Company 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.

C. Organizational structure.

Hawker owns, directly or indirectly, all of the issued and outstanding securities of Mar Oil Company, incorporated in the state of Delaware and registered to carry on business in the state of Ohio.

D. Property, plant and equipment.

Description of Properties

The following is a description of the Company’s six principal properties on production or under development.

Lavoy Area

The Lavoy area is located approximately 100 kilometres east of Edmonton in a well-developed natural gas-prone portion of the Western Canada Sedimentary Basin. Hawker does not operate the property, but owns a 45% average working interest in this property’s land, facilities, and production which from July 1 to December 31, 2003 averaged 14.4 mmcf/d. Hawker has ownership of a large undeveloped land base totalling 142,043 net acres (290,169 gross acres). Geologically, the property is characterized by 14 multi-stacked prospective horizons where hydrocarbons have been proven to exist. Hawker also has a working interest position in 10 processing facilities in the area with gross cumulative capacity of 40 mmcf/d.

In 2003, Hawker increased its net land position at Lavoy by purchasing approximately 3,500 net undeveloped acres through Crown land sales. During the year, Hawker participated in the drilling of 31 natural gas wells of which 23 were cased. As at December 31, 2003, only 12 of these wells had been connected into processing facilities and/or pipelines. The Company and the Lavoy operator are taking steps to accelerate the tie-in process.

Hawker and its partner negotiated a farm–in on additional lands with a major operator in the Lavoy region. Drilling success on these lands will increase Hawker’s land position in 2004.

With a large undeveloped land base, geologically multi-stacked prospective horizons, access to processing facilities and compression, Lavoy is Hawker’s largest core area and one where the Company intends to grow its base production and expand operations.

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Cold Lake/Bonnyville

The Cold Lake/Bonnyville property is located approximately 80 kilometres south of the Cold Lake Air Weapons Range in North Central Alberta. The Cold Lake/Bonnyville property falls outside of the restrictive gas over bitumen area ordered by the Alberta Energy Utilities Board (“EUB”). While Hawker’s drilling operations on the property have not been affected by the order, tie-in and production delays have been experienced.

Hawker assumed operatorship of this property in September 2003 and operates an average of 8 mmcf/d of natural gas production. Net production in 2003 was 2.0 mmcf/d which reflects Hawker’s average 25% working interest in Cold Lake/Bonnyville. Hawker has a solid land position in the area totalling some 12,840 net acres including 4,320 undeveloped net acres (10,240 gross acres). The property consists of 29 well sites and one production facility. Similar to the Lavoy area, Cold Lake’s geology is multi-stacked with five prospective hydrocarbon-bearing horizons.

Two natural gas wells were drilled and connected to processing facilities in late 2003. The wells will begin producing in the first half of 2004 after receiving regulatory approval. Since assuming operatorship, Hawker spent the remainder of 2003 reviewing all aspects of this area in detail: facility capacity, geologic potential, mineral rights availability, as well as possible competition from third-party operators. Hawker is encouraged by the gas exploitation upside of the Cold Lake/Bonnyville area and its potential for contribution to the Company’s future growth.

North Boundary

The North Boundary project is located 55 kilometres northeast of Fort St. John in British Columbia. Hawker acquired this property through its acquisition of Pointwest on December 30, 2003. The assets in this region fit well within Hawker’s identified area of interest. The development of the project is in its infancy and it offers Hawker a base for future low risk expansion as well as exploration potential. The Company will be focused on exploiting production from this core region for the next several years. Hawker has an average 85% working interest in the 42,000 acre land block, which comprises 25,993 net acres of undeveloped land. Production at December 31, 2003 was approximately 3,100 boe/d, comprising 17 mmcf/d of natural gas and 240 bbls/d of oil and NGLs. Hawker operates 22 natural gas producing wells, and has a 100% working interest in the North Boundary gas processing facility, which has a capacity of 28 mmcf/d of sour gas, 6 mmcf/d of sweet gas and 600 barrels per day of oil and NGLs. At North Boundary, hydrocarbons are produced from eight prospective horizons to a depth of approximately 1,300 metres.

As of year-end, more than 25 prospective locations for exploration or development drilling were identified. With current 3D seismic coverage over the majority of the property, and more seismic to be added in 2004, Hawker expects to expand its presence and production in the area. Hawker believes North Boundary will be a key asset in fuelling the Company’s growth in 2004.

The Company is currently in the process of transferring the permits registered in the name of Pointwest to Hawker in respect of the North Boundary property

Valhalla

The Valhalla property is located 160 kilometres northwest of Grande Prairie, in north central Alberta. Its multiple geological targets are found at a depth of approximately 1,800 metres in the Cretaceous formations common to Alberta production. Hawker currently has a working interest in 1,940 gross acres with a rolling option farmin on an additional 4,160 gross acres granted by a major resource company.

Three producing wells have been drilled on Hawker’s acreage. The wells have been connected to third party processing facilities in the area. Production at December 31, 2003 was 220 barrels per day, comprising 1 mmcf/d of natural gas and 55 boed/d of oil and NGLs. Two standing wells which have been drilled but are not yet tied into pipelines are expected to be brought on production in 2004. Several re-completion opportunities have also been identified and could be started in 2004.

The surrounding area is dominated by several large oil and gas companies, and offers Hawker limited opportunities for growth beyond 2004. As a result the Company will evaluate future plans for this property, including a possible exchange or sale.

Chigwell

Chigwell is a grassroots exploration prospect that was developed by Hawker in the second half of 2003. Hawker has reviewed more than 100 existing well data sets to identify the Chigwell opportunity. Hawker acquired its land position at

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Chigwell in the third quarter of 2003, with two exploration wells subsequently drilled and cased. Both of these wells tested at commercial flow rates of natural gas from the Basal Quartz/Ellerslie horizon.

This area is well developed in terms of infrastructure, and Hawker has initiated discussions with third party facility operators regarding access to available processing and gathering capacity. Hawker plans to drill two follow-up well locations in early 2004 in conjunction with additional land and seismic data acquisitions.

The Chigwell area is viewed as an emerging focus area for Hawker. The project exemplifies Hawker’s ability to identify drilling opportunities and exploit them quickly.

Purple Springs

At Purple Springs in southern Alberta, Hawker farmed in on 6,400 gross acres of land where the Company plans to drill and tie in 15 wells by June 30, 2004 to earn a 50% working interest position. The program will capitalize on Hawker’s significant technical experience in developing shallow Medicine Hat gas sands throughout southern Alberta. Future opportunities for the block and offsetting lands involve infill drilling, and gathering and processing of third party natural gas through the facilities Hawker will develop in this area. Exploration prospects for deeper targets in the Viking, Sunburst, and Sawtooth formations may be evaluated as part of the 2004 drilling program.

Wild River Prospect

The Wild River project is non-operated and constitutes a significant part of Hawker’s 2004 high risk exploration portfolio. Hawker has a 20% working interest in five sections of land as well as the associated seismic coverage. The Wild River prospect is a Nisku pinnacle reef on trend with existing pinnacle reef production to the south. The feature was identified by seismic re-processing and as mapped could have significant gas-in-place relative to the analogous pinnacles in the area. The well located at 8-14-57-23 W5M was spudded in December 2003 and at year-end was drilling forward. Subsequent to year-end the well was cased and is currently being evaluated by Hawker and its partners.

Other

In conjunction with Hawker’s acquisition of Southward on April 30, 2003, the Company acquired access to a large seismic database covering northeast British Columbia, and extending southeast to the southern Alberta prairies. The database included some 1,250 kilometres of 2D seismic data and 2,750 square kilometres of 3D seismic information. Hawker’s exploration teams have extensively reviewed and re-processed certain data to develop an inventory of potential exploration prospects. Land acquisition strategies have been developed for these prospects and in some cases land has been acquired. Hawker expects to drill two of these prospects in early 2004, and will continue evaluation and land acquisition of the others.

In addition to North Boundary and Valhalla, 10 minor properties were acquired as part of the Pointwest acquisition. The properties are all non-operated with an average working interest of 30%. Net production at December 31, 2003 from the combined properties was 1.8 mmcf/d of natural gas and 22 bbls/d of oil and NGLs. Subsequent to December 31, 2003 and following an evaluation of the properties’ exploitation potential, the Company reached an agreement to sell these properties, with the closing expected at the end of the first quarter of 2004.

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Drilling Activity

The following table sets forth the number of gross and net exploratory and development wells in which the Company has participated during the periods indicated.


	Year Ended December 31 ⁽¹⁾
	2003
	Gross Wells ⁽²⁾		Net Wells ⁽³⁾
Exploratory
Natural Gas		5		3.0
Crude Oil		—		—
Dry and Abandoned ⁽⁴⁾		1		0.5

Total Exploratory		6		3.5

Development
Natural Gas		20		9.6
Crude Oil		2		1.0
Dry and Abandoned ⁽⁴⁾		7		3.5

Total Development		29		14.1

Total Drilling Activity		35		17.6

Notes:

(1) Prior to June 2003, the Company was not engaged in the exploration, development or production of oil or gas and did not hold any interests in any oil or gas properties.

(2) “Gross wells” means the total number of wells in which the Company has an interest.

(3) “Net wells” means the number of gross wells multiplied by the Company’s working interest therein.

(4) “Dry well” means a well which is not a productive well or a service well. A productive well is a well which is capable of producing oil and gas in commercial quantities or in quantities considered by the operator to be sufficient to justify the costs required to complete, equip and produce the well. A service well means a well such as a water or gas-injection, water-source or water-disposal well. Such wells do not have marketable reserves of crude oil or natural gas attributed to them but are essential to the production of the crude oil and natural gas reserves.

-19-

Location of Wells

The following table sets forth the Company’s interest in producing wells and wells capable of producing as at December 31, 2003.


	Wells⁽¹⁾
	Producing				Shut-in⁽⁴⁾
Property	Gross⁽²⁾		Net⁽³⁾		Gross⁽²⁾		Net⁽³⁾
Lavoy		170		76.5		24		10.8
North Boundary		23		16.1		—		—
Cold Lake/Bonnyville		25		9.3		12		4.8
Valhalla		4		3.2		1		0.7
Other		35		8.0		3		2.0

Total		257		113.1		40		18.3

Notes:

(1)Prior to June 2003, the Company was not engaged in the exploration, development or production of oil or gas and did not hold any interests in any oil or gas properties.

(2)“Gross wells” means the total number of wells in which the Company has an interest.

(3)“Net wells” means the number of gross wells multiplied by the Company’s working interest therein.

(4)“Shut-in Wells” are wells which are capable of economic production or which the Company considers capable of production but which, for a variety of reasons, including but not limited to lack of markets or development, are not currently on production.

Land Holdings

The following table summarizes the undeveloped land of the Company as at December 31, 2003.


Property	Gross Acres ⁽¹⁾		Net Acres ⁽²⁾
Lavoy		290,169		142,043
Cold Lake/Bonnyville		10,240		4,320
North Boundary		28,710		25,993
Valhalla		640		640
Chigwell		960		960
Wild River		3,200		640
Other		16,464		10,333

Total		350,383		184,929

Notes:

(1)“Gross Acres” means the total acres in which the Company has an interest.

(2)“Net Acres” means the total acres in which the Company has an interest multiplied by the working interest therein.

Production

Average Daily Production Volumes

Prior to June 2003, the Company was not engaged in the exploration, development or production of oil or gas and did not hold any interests in any oil or gas properties.

The average daily production volumes for the Company for 2003 are set out below.


	2003
	3^rd Quarter		4^th Quarter		Annual Average
Natural Gas (mmcf/d)		16.7		16.2		16.3
Price ($/mcf)		5.81		5.88		5.84
Royalties		1.57		1.21		1.40
Production Costs		0.55		0.80		0.67
Netback		3.69		3.87		3.77

- 20 -

Selected Reserve Information

The following tables set forth certain information relating to the oil and natural gas reserves of the Company’s properties and the present value of the estimated future net cash flow associated with such reserves as at December 31, 2003. The information set forth below is derived from the McDaniel Report and the GLJ Report which have been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in National Instrument 51-101 (“NI 51-101”) and the COGE Handbook. All evaluations and reviews of future net cash flow are stated prior to any provision for interest costs or general and administrative costs and after the deduction of estimated future capital expenditures for wells to which reserves have been assigned. It should not be assumed that the estimated future net cash flow shown below is representative of the fair market value of the Company’s properties. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGLs and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, NGLs and natural gas reserves may be greater than or less than the estimates provided herein.

The Company has a reserves committee of independent board members which reviews the qualifications and appointment of the independent qualified reserves evaluators. The committee also reviews the procedures for providing information to the evaluators. All booked reserves are based upon annual evaluation and review by the independent qualified reserves evaluators.

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003

CONSTANT PRICES AND COSTS


	RESERVES
	LIGHT AND				NATURAL				NATURAL GAS
	MEDIUM OIL				GAS				LIQUIDS
	Gross		Net		Gross		Net		Gross		Net
RESERVES CATEGORY	(mbbl)		(mbbl)		(mmcf)		(mmcf)		(mbbl)		(mbbl)
Proved
Developed Producing		164.5		156.2		30,857.9		23,397.4		135.1		105.0
Developed Non-Producing		13.3		13.0		7,255.8		5,490.3		23.3		17.3
Undeveloped		42.5		31.4		885.1		619.3		3.5		2.1

Total Proved		220.3		200.6		38,998.8		29,507.0		161.9		124.4
Probable		68.9		64.9		11,540.5		8,742.7		40.3		30.8

Total Proved Plus Probable		289.2		265.5		50,539.3		38,249.7		202.2		155.2


	NET PRESENT VALUES OF FUTURE NET REVENUE
	BEFORE INCOME TAXES DISCOUNTED AT										AFTER INCOME TAXES DISCOUNTED AT
	(%/year)										(%/year)
	0		5		10		15		20		0		5		10		15		20
RESERVES CATEGORY	(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)
PROVED
Developed Producing		126,270		109,435		97,321		88,117		80,845		126,270		109,435		97,321		88,118		80,846
Developed Non- Producing		26,674		24,004		21,868		20,118		18,656		26,675		24,004		21,868		20,118		18,656
Undeveloped		2,859		2,250		1,794		1,449		1,183		2,858		2,250		1,794		1,449		1,183

Total proved		155,803		135,689		120,983		109,684		100,684		155,803		135,689		120,983		109,685		100,685
Probable		45,705		34,607		27,591		22,754		19,233		39,644		29,688		23,544		19,385		16,398

Total Proved Plus Probable		201,508		170,296		148,574		132,438		119,917		195,447		165,377		144,527		129,070		117,083

- 21 -

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003

CONSTANT PRICES AND COSTS

Future

Net

Revenue

Well

Before

After

Operating

Development

Abandonment

Income

Reserves

Revenue

Royalties

Costs

Taxes

Category

(M$)

Proved Reserves

249,009

56,310

28,198

3,575

5,123

155,803

Proved Plus Probable Reserves

322,286

72,641

36,227

6,696

5,214

201,508

6,061

195,447

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003

CONSTANT PRICES AND COSTS


		FUTURE NET REVENUE
		BEFORE INCOME TAXES &
		ARTC
		(discounted at 10%/year)
RESERVES CATEGORY	PRODUCTION GROUP	(M$)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-
	products)		373
	Natural Gas (including by-products but excluding solution gas
	from oil wells		108,193

Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-
	products)		766
	Natural Gas (including by-products by excluding solution gas
	from oil wells)		132,820

SUMMARY OF OIL AND GAS RESERVES
AND NET PRESENT VALUES OF FUTURE NET REVENUE
as of December 31, 2003

FORECAST PRICES AND COSTS


	RESERVES
	LIGHT AND				NATURAL				NATURAL GAS
	MEDIUM OIL				GAS				LIQUIDS
	Gross		Net		Gross		Net		Gross		Net
Reserves Category	(mbbl)		(mbbl)		(mmcf)		(mmcf)		(mbbl)		(mbbl)
Proved
Developed Producing		164.5		156.6		30,818.2		23,353.9		135.0		105.0
Developed Non-Producing		13.3		13.0		7,249.8		5,482.3		23.4		17.3
Undeveloped		42.5		32.3		885.1		620.3		3.5		2.1

Total proved		220.3		201.9		38,953.1		29,456.5		161.9		124.4
Probable		69.6		65.4		11,528.7		8,731.4		40.4		31.0

Total Proved Plus Probable		289.9		267.3		50,481.8		38,187.9		202.3		155.4

- 22 -

NET PRESENT VALUES OF FUTURE NET REVENUE


	BEFORE INCOME TAXES DISCOUNTED AT										AFTER INCOME TAXES DISCOUNTED AT
	(%/year)										(%/year)
	0		5		10		15		20		0		5		10		15		20
Reserves Category	(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)		(MM$)
Proved
Developed Producing		107,795		94,662		85,126		77,812		71,976		107,795		94,662		85,126		77,812		71,976
Developed Non- Producing		22,300		20,323		18,706		17,358		16,214		22,300		20,323		18,706		17,358		16,214
Undeveloped		1,867		1,472		1,159		917		728		1,867		1,473		1,159		917		728

Total proved		131,962		116,457		104,991		96,087		88,918		131,962		116,458		104,991		96,087		88,918
Probable		36,293		27,534		22,051		18,286		15,544		36,293		27,533		22,051		18,286		15,544

Total Proved Plus Probable		168,255		143,991		127,042		114,373		104,462		168,255		143,991		127,042		114,373		104,462

TOTAL FUTURE NET REVENUE
(UNDISCOUNTED)
as of December 31, 2003

FORECAST PRICES AND COSTS

Future Net

Well

Revenue

Operating

Development

Abandonment

Before

Income

After Income

Reserves

Revenue

Royalties

Costs

Income Taxes

Taxes

Category

(M$)

(M$)⁽¹⁾

(M$)

Proved Reserves

222,255

50,058

30,673

3,650

5,912

131,962

Proved Plus Probable Reserves

285,134

63,824

40,025

6,913

6,117

168,255

FUTURE NET REVENUE
BY PRODUCTION GROUP
as of December 31, 2003

FORECAST PRICES AND COSTS


		FUTURE NET REVENUE
		BEFORE INCOME TAXES &
		ARTC (discounted at 10%/year)
RESERVES CATEGORY	PRODUCTION GROUP	(M$)
Proved Reserves	Light and Medium Crude Oil (including solution gas and other by-
	products)		310
	Natural Gas (including by-products but excluding solution gas
	from oil wells)		94,955

Proved Plus Probable Reserves	Light and Medium Crude Oil (including solution gas and other by-
	products)		602
	Natural Gas (including by-products by excluding solution gas
	from oil wells)		114,703

Notes:

(1)“Gross Reserves” include working interest reserves before the deduction of royalties.

(2)“Net Reserves” include working interest after royalty deductions plus royalty interest reserves.

(3)The net cumulative cash flow forecasts are after direct lifting costs, freehold royalties, Crown mineral taxes and future investments. An allowance for future well abandonment costs for all working interest wells was included, however, no allowance was made for the abandonment of any facilities.

(4)“Royalties” refers to royalties paid to others. The royalties deducted from the reserves are based on the percentage royalty calculated by applying the applicable royalty rate or formula. In the case of Crown sliding scale royalties which are dependent on selling prices, the price forecasts for the individual properties in question have been employed.

- 23 -

(5) “Reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

(6) “Proved Reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(7) “Probable Reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

(8) “Developed Reserves” are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

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

(10) “Developed Non-Producing Reserves” are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(11) “Undeveloped Reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.

(12) The pricing assumptions used in the McDaniel Report with respect to net cumulative cash flow as well as the inflation rates used for operating costs are set forth below.

SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS
as of December 31, 2003

FORECAST PRICES AND COSTS



			OIL
									NATURAL		Edmonton
	WTI		Edmonton		Hardisty		Cromer		GAS⁽¹⁾		Cond. &
	Cushing		Par Price 40º		Heavy		Medium		AECO Gas		Natural		INFLATION		EXCHANGE
	Oklahoma		API		12º API		29.0º API		Price		Gasolines		RATES		RATE
Year	($US/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/bbl)		($Cdn/GJ)		($CDn/bbl)		%/Year		($US/Cdn)
Historical
2000		30.31		44.72		27.80		40.10		5.32		46.25		2.7		0.674
2001		25.97		39.60		18.05		32.22		5.15		42.42		2.6		0.646
2002		26.10		39.95		27.60		34.93		3.86		40.65		2.2		0.637
2003		30.95		43.10		27.45		36.90		6.30		43.70		2.0		0.715
Forecast
2004		29.00		37.70		22.70		32.20		5.50		38.45		2.0		0.750
2005		26.50		34.30		21.55		29.71		5.19		35.07		2.0		0.750
2006		25.50		33.00		21.56		28.84		4.87		33.78		2.0		0.750
2007		25.00		32.30		20.63		28.06		4.68		33.10		2.0		0.750
2008		25.00		32.30		20.39		27.97		4.53		33.11		2.0		0.750
2009		25.50		32.90		20.76		28.48		4.57		33.73		2.0		0.750
2010		26.00		33.50		21.11		29.00		4.60		34.34		2.0		0.750
2011		26.50		34.20		21.56		29.61		4.69		35.06		2.0		0.750
2012		27.00		34.80		21.91		30.11		4.78		35.68		2.0		0.750
2013		27.50		35.50		22.35		30.72		4.87		36.40		2.0		0.750
2014		28.10		36.20		22.79		31.32		4.97		37.11		2.0		0.750
2015		28.70		37.00		23.32		32.03		5.08		37.93		2.0		0.750
2016		29.30		37.80		23.85		32.73		5.19		38.75		2.0		0.750
2017		29.90		38.60		24.37		33.43		5.29		39.57		2.0		0.750
2018		30.50		39.30		24.79		34.02		5.40		40.29		2.0		0.750
2019		31.10		40.10		25.30		34.72		5.51		41.11		2.0		0.750
2020		31.70		40.90		25.80		35.41		5.61		41.93		2.0		0.750
2021		32.30		41.70		26.30		36.10		5.72		42.75		2.0		0.750
2022		32.90		42.40		26.69		36.69		5.82		43.47		2.0		0.750
2023		33.60		43.30		27.28		37.47		5.95		44.39		2.0		0.750
Thereafter		33.60		43.30		27.28		37.47		5.95		44.39		0.0		0.750

(13) Operating costs were escalated at a rate of 2.0% per year. The exchange rate used for the US/Canadian dollar for 2004 was 0.75, for 2005 was 0.75, for 2006 was 0.75, for 2007 was 0.75 and for 2008 and beyond was 0.75.

- 24 -

(14) For the constant price evaluations, the McDaniel Report used product prices in effect as at December 31, 2003 of $39.76 (Edmonton Par Light) per bbl of oil and $5.87 (Alberta Average) per mmbtu of natural gas.

(15) McDaniel and GLJ have estimated total capital costs of $6,913,000 and $6,696,000 (undiscounted) in order to achieve the future proved plus probable net revenues, of which $3,684,000 and $3,611,000 will be incurred in 2004 and $2,982,000 and $2,866,000 in 2005 based on Forecast and Constant prices respectively.

(16) Total burdens include crown, freehold and overriding royalties as well as mineral taxes.


							ASSOCIATED AND
	LIGHT AND MEDIUM OIL						NON-ASSOCIATED GAS								NATURAL GAS LIQUIDS
												Net
					Net Proved							Proved
	Net		Net		Plus		Net			Net		Plus							Net Proved Plus
	Proved		Probable		Probable		Proved			Probable		Probable			Net Proved		Net Probable		Probable
Factors	(mbbl)		(mbbl)		(mbbl)		(mmcf)			(mmcf)		(mmcf)			(mbbl)		(mmbl)		(mbbl)
December 31, 2002		—		—		—		—			—		—			—		—		—
Extensions		—		—		—		2,892.6			1,207.1		4,099.7			—		—		—
Improved Recovery		—		—		—		—			—		—			—		—		—
Technical Revisions		—		—		—		—			—		—			—		—		—
Discoveries		—		—		—		—			—		—			—		—		—
Acquisitions		201.9		64.5		267.3		29,571.5			7,524.3		37,095.8			124.4		31.0		155.4
Dispositions		—		—		—		—			—		—			—		—		—
Economic Factors		—		—		—		—			—		—			—		—		—
Production		—		—		—		(3,007.6	)		—		(3,007.6	)		—		—		—
December 31, 2003		201.9		64.5		267.3		29,456.5			8,731.4		38,187.9			124.4		31.0		155.4

Reconciliation of Reserves

Prior to June 2003, the Company was not engaged in the exploration, development or production of oil or gas and did not hold any interests in any oil or gas properties. Accordingly, the Company did not have any reserves prior to June 2003.

Additional Information Relating to Reserves Data

Prior to June 2003, the Company was not engaged in the exploration, development or production of oil or gas and did not hold any interests in any oil or gas properties.

Undeveloped Reserves

The following table summarizes the gross volumes of proved undeveloped reserves that were first attributed in each of the most recent financial years:


	2003
Product
Light and Medium Crude Oil(mbbls)		42.5
Natural Gas (mmcf)		885.1
Natural Gas Liquids (mbbls)		3.5

Total (mbbls)		193.5

The following table summarizes the gross volumes of probable reserves that were first attributed in each of the most recent financial years:


	2003
Product
Light and Medium Crude Oil (mbbls)		69.6
Natural Gas (mmcf)		11,528.7
Natural Gas Liquids (mbbls)		40.4

Total (mbbls)		2,031.5

- 25 -

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

Future Development Costs

The following table outlines development costs deducted in the estimation of future net revenue calculated using no discount.


	2004		2005		2006		2007		2008
	($ Thousands)		($ Thousands)		($ Thousands)		($ Thousands)		($ Thousands)
Reserve Category
Proved Reserves (Constant Prices and Costs)		3,412		150		—		—		12
Proved Reserves
(Forecast Prices and Costs)		3,480		156		—		—		14
Proved & Probable Reserves
(Forecast Prices and Costs)		3,684		2,982		27		27		110

The Company has established a $56 million capital program to fund its exploration and development activities for the 2004 year. Such financing consists of internally generated cash flows and possible proceeds from minor divestitures of interests in non-principal properties acquired pursuant to the acquisitions of Pointwest and Zorin. The Company is currently evaluating the interests acquired pursuant to the acquisitions of Pointwest and Zorin. Any decision to divest any interest in such properties will only be contemplated once such evaluations are complete. The Company’s capital program does not include any corporate acquisition opportunities, which would likely be financed through debt or equity financings.

Other Oil And Gas Information

Oil and Gas Properties and Wells

As at December 31, 2003, the Company had an interest in 257 gross (113.1 net) producing and 40 gross (18.3 net) non-producing oil and natural gas wells as follows:


	PRODUCING				NON-PRODUCING
	Gross⁽¹⁾		Net⁽²⁾		Gross⁽¹⁾		Net⁽²⁾
Wells
Alberta		234		97.0		40		18.3
British Columbia		23		16.1		—		—

TOTAL		257		113.1		40		18.3

Notes:

(1)“Gross” wells means the number of wells in which the Company has a working interest or a royalty interest that may be convertible to a working interest.

(2)“Net” wells means the aggregate number of wells obtained by multiplying each gross well by the Company’s percentage working interest therein.

- 26 -

Properties with No Attributed Reserves

The following table sets forth the gross and net acres of unproved properties held by the Company and the net area of unproved property for which the Company expects its rights to explore, develop and exploit to expire during the next year:

UNPROVED PROPERTIES
(acres)


LOCATION	Gross		Net		Net Area to Expire in 2004
Manitoba		80		18		0
Alberta		321,593		158,918		19,757
British Columbia		28,710		25,993		4,180

TOTAL		350,383		184,929		23,937

Abandonment & Reclamation Costs

An allowance for future well abandonment costs was made for all of the Company’s working interest wells, however, no allowance was made for the reclamation of well sites or the abandonment and reclamation of any facilities.

Costs Incurred

The following table outlines costs incurred during the financial year ended December 31, 2003.

Property Acquisitions, Dispositions and Capital Expenditures


Nature of cost	Amount ($M)
Property Acquisition Costs
Proved		—
Unproved		—
Exploration Costs		7,592
Development Costs		6,912

Total		14,504

Exploration and Development Activities

The following table summarizes the results of exploration and development activities during the financial year ended December 31, 2003.


	Gross		Net
Development Wells
Gas		20		9.6
Oil		2		1.0
Service		—		—
Dry		7		3.5
Exploratory Wells
Gas		5		3.0
Oil		—		—
Service		—		—
Dry		1		0.5

Total Wells		35		17.6

The Company intends to continue to develop its principal properties as well as continue its grassroots exploration program to establish new core areas in Alberta and British Columbia. Hawker will continue to target natural gas properties with multiple horizons in the Western Canada Sedimentary Basin. These exploration and development activities will be financed through a $56 million capital program for the 2004 year, which financing consists of internally generated cash flow and proceeds from divestitures of interests in non-principal properties.

- 27 -

Production Estimates

The following tables summarize the volume of total proved production estimated for 2004 using constant and forecast prices and costs.


	ESTIMATED PRODUCTION
	Constant Prices and Costs		Forecast Prices and Costs
Light and Medium Crude Oil (boe/d)		123		123
Natural Gas (mcf/d)		30,250		30,250
Natural Gas Liquids (boe/d)		111		111

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulation pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases or emissions of various substances produced or utilized in association with certain oil and gas industry operations. In addition, 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. A breach of such legislation may result in the imposition of material fines and penalties, the revocation of necessary licenses and authorizations and civil liability for pollution damage.

In 1994, the United Nations’ Framework Convention on Climate Change came into force and three years later led to the Kyoto Protocol which will require, upon ratification, nations to reduce their emissions of carbon dioxide and other greenhouse gases. As a result of Canada’s ratification of the Kyoto Protocol reductions in greenhouse gases from the Company’s operations may be required which could result in increased capital expenditures and reductions in production of oil and gas.

The Company does not face any environmental issues or impacts that are unique to the Company. However, like all participants in the Canadian oil and gas industry, reclamation and restoration of abandoned wells and facilities is recognized as a corporate responsibility. The expenses associated with meeting this responsibility are provided for on a unit of production basis.

Item 5. Operating and Financial Review and Prospects

Overview

At the Annual and Special Meeting of SYNSORB Biotech Inc. (“SYNSORB”) shareholders held April 3, 2003, shareholders approved the planned conversion of the company into an oil and gas enterprise and changed the company’s name to Hawker Resources Inc. Prior to 2002, SYNSORB conducted pharmaceutical drug development activities. On December 10, 2001 SYNSORB terminated development of SYNSORB Cd® including its phase III clinical trials. Subsequent to December 10, 2001 SYNSORB had no drug in active development and was seeking strategic alternatives.

On June 30, 2003, the conversion of the Company to an oil and gas enterprise was completed when Hawker acquired natural gas properties located in the Lavoy and Cold Lake areas. Hawker’s 2003 operating results reflect the costs of converting Hawker into an oil and gas enterprise and the results of its first six months of oil and gas operations. Accordingly, the 2003 operating results are not directly comparable to the 2002 operating results when the Company was winding down its biotech operations and seeking strategic alternatives.

A. Operating Results

Year ended December 31, 2003 compared with Year ended December 31, 2002

Production revenue for the year ended December 31, 2003 was $17,582,000. The second half of 2003 marked the commencement of oil and gas operations for the Company and accordingly, there were no production revenues for the year ended December 31, 2002.

All of the Company’s production was natural gas. Natural gas sales volumes for the six months ended December 31, 2003 averaged 16,346 mcf/d and the average price received was $5.84 per mcf. Hawker’s production was from the Lavoy area and the Cold Lake/Bonnyville area.

- 28 -

The majority of the Company’s natural gas production is sold to aggregators and the Company receives AECO spot or AECO month index prices. The Company has entered into commodity price contracts to reduce the volatility of commodity prices and to ensure that funds are available to support planned capital expenditures.

Interest income for the year ended December 31, 2003 was $78,000 versus $32,000 for the year ended December 31, 2002. The increases were due to higher cash balances on hand during the first half of 2003 when the Company did not have bank debt, as compared to 2002.

Other revenue received by the Company during 2003 primarily related to an exclusive license agreement of certain of its patents regarding toxin-binding sugars. Pursuant to this license agreement, the Company received net proceeds of $375,000. The Company also received a milestone payment of $105,000 with respect to the previous sale of its INH Technologies Inc. subsidiary. Other revenue of $107,000 received during the year ended December 31, 2002 also related to a milestone payment received by the Company with respect to the previous sale of its INH Technologies Inc. subsidiary. The Company cannot predict the likelihood, timing or amount of any further milestone or licensing receipts.

Royalty expense for the year ended December 31, 2003 was $4,205,000, or 24% of production revenue. There was no royalty expense for 2002 as the Company did not have oil and gas operations.

Production expense for 2003 was $2,028,000 or $0.67 per mcf, including accretion expense of $100,000. There was no production expense for 2002 as the Company did not have oil and gas operations.

Net general and administrative expense for the year ended December 31, 2003 was $4,590,000, an increase of 183% from the $1,621,000 for the year ended December 31, 2002. The increase in general and administrative expenses was attributable to the addition of staff, use of consultants and increased general administrative costs associated with the Company becoming a fully operational oil and gas entity. General and administrative expenses totalling $564,000 were capitalized for the year ended December 31, 2003.

Interest expense for the year ended December 31, 2003 was $679,000 as compared with $71,000 for the year ended December 31, 2002. The increase in interest expense was a result of using the credit facility as an operating line of credit and to fund asset acquisitions.

Depletion and depreciation expense for the year ended December 31, 2003 was $8,933,000 as compared with $26,000 for the year ended December 31, 2002. On a unit of production basis, depletion and depreciation expense on oil and gas assets was $17.79 per boe for the year ended December 31, 2003. Depletion and depreciation associated with oil and gas assets accounted for the large increase in depletion and depreciation expense for 2003 as compared with 2002. Depreciation expense for 2002 related solely to computer equipment and office furniture and equipment.

In 2003, the Company retroactively adopted the recommendations of the Canadian Institute of Chartered Accountants on accounting for asset retirement obligations. The new pronouncement requires the Company to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying value of the related long-lived asset. The liability is subsequently adjusted due to the passage of time, and is recognized as an accretion expense in the statement of earnings. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the capital asset is amortized using the unit of production method based on estimated gross proven reserves as determined by independent engineers.

The Company did not have long-lived assets subject to retirement obligations as at December 31, 2002 and therefore this change in accounting policy had no impact on the December 31, 2002 financial statements. The effect of this change on the December 31, 2003 balance sheet was an increase in capital assets of $3,191,000 and the recognition of an asset retirement obligation of $3,499,000. The change in accounting for asset retirement obligations as compared to the site restoration approach resulted in an increase in net earnings of $217,000 for the year ended December 31, 2003 ($0.01 per share).

Effective January 1, 2003, the Company adopted the recommendations of the Canadian Institute of Chartered Accountants on accounting for stock based compensation. Under this new pronouncement, stock based compensation expense is recorded for all stock options granted on or after January 1, 2003. For the year ended December 31, 2003, the impact of the adoption of this standard on the financial statements as at December 31, 2003 was a decrease in net earnings of $132,000 ($0.01 per share) and a corresponding increase in contributed surplus.

During the third quarter of 2003, the Company consolidated its office space. A provision of $322,000 was made during the third quarter for residual lease costs on office space no longer occupied by the Company. This provision was increased by $180,000 to a total of $502,000 during the fourth quarter when sublease arrangements were modified. There

- 29 -

was no lease abandonment expense for 2002.

Assets held for sale are comprised of the pharmaceutical manufacturing facility and related manufacturing equipment associated with the former biotech operations of the Company. For the year ended December 31, 2003, operating costs and write-downs associated with assets held for sale were $190,000 as compared with $7,408,000 for the year ended December 31, 2002. During 2003, the Company wrote-down the carrying value of assets held for sale by $145,000 to the estimated net realizable value. During 2002, assets held for sale were written down by a total of $7,097,000.

The Company’s current income tax expense was solely comprised of the Large Corporations Tax, and for the year ended December 31, 2003, totaled $345,000. There was no tax expense for the year ended December 31, 2002. The increase is due to the higher capital base of the Company attributable to the debt and equity financings completed during 2003.

On December 5, 2003, the Company issued 2,900,000 flow-through shares for $15,225,000. In accordance with the agreements between the Company and the flow-through shareholders, the Company renounced $15,225,000 of Canadian Cumulative Exploration Expense as of December 31, 2003. This renunciation gave rise to a future tax liability of $5,271,000. The tax pools of the Company are sufficient to offset this liability and accordingly, a future tax recovery was recognized in an equal amount.

Year ended December 31, 2002 compared with Year ended December 31, 2001

At December 31, 2001 the Company owned 6,255,800 common shares of Oncolytics Biotech Inc. (“Oncolytics”). Effective May 15, 2002 the Company distributed to its shareholders 4,000,235 common shares of Oncolytics which was accounted for as a return of capital. The deemed value of these shares, net of expenses, was $11,600,000 resulting in a gain on distribution of $8,325,000. As part of this transaction, the Company’s holding of 1,500,000 shares in BCY Life Sciences Inc. was transferred to Oncolytics. No gain or loss was recorded as a result of that transfer.

During the year ended December 31, 2002 the Company sold 2,255,565 common shares of Oncolytics for net proceeds of $6,898,000 resulting in a gain on sale of $4,899,000. As at December 31, 2002 the Company did not hold any common shares of Oncolytics.

For the year ended December 31, 2002, the Company had total revenue of $139,000 compared to $729,000 for the year ended December 31, 2001. Interest income for the 12 months ended December 31, 2002 decreased significantly compared to the same period in 2001 as a result of lower average cash balances on hand and lower interest rates in 2002.

Expenses for the year ended December 31, 2002 of $9,126,000 were less than the expenses of $26,803,000 for the comparable period in 2001. Because the Company had terminated research and development in late 2001 and made a provision in that year for future wind down costs associated with drug development, research development expenses in 2002 were nil. Operating expenses for the 2002 period were $1,596,000, a significant reduction from $7,106,000 for 2001. The reduction is due to the termination of almost all employees, the termination of certain office space effective April 11, 2002 and the consolidation of all activity at the manufacturing facility.

Interest on long term debt in 2002 was $71,000, a significant reduction from $787,000 in 2001 due to the payment by the Company during 2002 of all of its long and short-term debt. Amortization in 2002 was $7,216,000 compared to $9,655,000 in 2001. Included in the 2001 amortization amounts was property and other capital asset write-downs of $8,203,000 arising from the termination of the Company’s drug development program. The amortization in 2002 included additional write-downs of the Company’s equipment and manufacturing facility based on the Company’s determination that those assets could only be sold on the basis of general commercial conditions and not their drug specific attributes.

B. Liquidity and capital resources

Year ended December 31, 2003 compared with Year ended December 31, 2002

Pursuant to various financing agreements entered into April 3, 2003, the Company raised $3,645,000 through the issue of 430,493 Series A Debentures for $3,616,000, 430,493 Series A Warrants for $12,000, 2,152,465 voting preferred shares for $6,000 and 3,874,437 non-voting preferred shares for $11,000.

Each Series A Warrant entitled the holder thereof to purchase five common shares and nine Class A common shares on the concurrent surrender of the warrant, five voting preferred shares, nine non-voting preferred shares, and one Series A Debenture. On May 29, 2003, immediately after the issue of a receipt for the prospectus offering common shares for sale

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and issue, the Series A Warrants were exercised and the Company issued 2,152,465 common shares and 3,874,437 Class A common shares upon the surrender of the voting and non-voting preferred shares and Series A Debentures.

On May 29, 2003, the Company issued a fully marketed prospectus offering of 14,286,000 common shares to the public priced at $3.15 per share. The issuance was fully subscribed and the public offering was completed on June 12, 2003. The Company received $42,301,000, net of underwriting fees.

On December 5, 2003, the Company issued through a private placement, 2,900,000 common shares on a flow-through basis at a price of $5.25 per share. The Company received $14,514,000, net of underwriting fees.

On December 30, 2003, the Company issued, pursuant to a prospectus offering, 11,200,000 common shares at a price of $4.05 per share. The Company received $43,092,000, net of underwriting fees.

On March 31, 2003 the Company acquired all of the shares of 1022971 Alberta Ltd. (“1022971”) for a nominal amount and the Company was assigned an option to purchase up to a 49% interest in certain oil and gas properties west of the 4th meridian (“W4M Properties”) owned by Southward Energy Ltd. (“Southward”). On April 30, 2003, 1022971 acquired all of the shares of Southward. Immediately thereafter, Southward sold its oil and gas properties, excluding a 1% undivided interest in the W4M Properties and a 100% interest in seismic data, to an independent third party.

On June 30, 2003, the Company exercised its option to purchase the W4M Properties. Further on June 30, 2003, the Company purchased the 1% undivided interest in the W4M Properties of Southward and the non-cash working capital of Southward was conveyed to the Company. Also on June 30, 2003, all of the shares of 1022971, which included Southward and all of its subsidiaries, were sold for nominal consideration to an independent third party. The total purchase price of the 50% interest in the W4M Properties and non-cash working capital of $71,337,000 was funded by the net proceeds of the prospectus offering and bank debt.

On August 14, 2003, the Company acquired all of the shares of 1053638 Alberta Ltd. and 1053639 Alberta Ltd., seismic data companies. On August 19, 2003, the Company sold all of the shares of 1053638 Alberta Ltd. The net cash consideration paid was $1,200,000. On December 31, 2003, 1053639 Alberta Ltd. was amalgamated with Hawker.

On December 30, 2003, Hawker acquired all of the shares of Pointwest Energy Inc., a privately held oil and gas company with operations in Alberta and B.C., for total consideration of $67,247,000, funded by bank debt and the net proceeds of the December 30, 2003 share issue. Pointwest Energy Inc. was amalgamated with Hawker on December 30, 2003. During the year ended December 31, 2003, the Company spent $14,783,000 on capital asset additions, excluding property acquisitions. There were no capital expenditures during 2002, reflecting the wind-down of the biotech operations of the Company.

Capital Expenditures


(in thousands of dollars)	Year Ended December 31, 2003
Exploration and Development Expenditures
Lease acquisition and retention		$	1,916
Geological and geophysical			4,674
Drilling and completion			5,439
Facilities and equipment			2,475

Total Exploration and Development Expenditures			14,504
Other capital assets			279

Total Capital Expenditures		$	14,783

During the second half of 2003, the Company participated in the drilling of 36 gross (17.4 net) wells. This resulted in 29 gross (13.9 net) wells and 7 gross (3.5 net) dry holes. As at December 31, 2003, 12 of these wells had been connected into processing facilities and/or pipelines.

For the year ended December 31, 2003, proceeds of $1,173,000 were received on assets held for sale as compared with $44,000 for the year ended December 31, 2002. The assets held for sale relate to the pharmaceutical manufacturing facility and related manufacturing equipment associated with the former biotech operations of the Company.

During the 2003, the Company received proceeds of $192,000 from the exercise of stock options under the stock option plan. The options exercised were granted while the Company was operating as a biotech firm.

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The Company has a $54 million extendible revolving term credit facility and a $10 million non-revolving bridge facility. As at December 31, 2003, $9.9 million of the extendible revolving term facility remained unutilized while the $10 million non-revolving bridge facility was fully utilized. The Company plans to use proceeds from oil and gas property sales to fund the repayment of the non-revolving bridge facility. The capacity of the extendible revolving term credit facility, combined with cash flow from operations, is expected to be sufficient to support the Company’s 2004 capital program.

As at December 31, 2003, the Company’s working capital deficiency was $17,828,000, including the bridge financing of $10,000,000, compared to working capital of $412,000 as at December 31, 2002, reflecting the business acquisitions and year end activity level of the Company.

Pursuant to the terms of a technology commercialization agreement pertaining to pharmaceutical drug development, the Company received a grant from the Alberta Heritage Foundation for Medical Research (“AHFMR”) in 1995. The Company was required to repay the amount advanced of $387,000 plus a royalty equivalent to the amount initially received. Any required repayment and royalty was based on gross sales of SYNSORB related products commencing January 1, 2000 with payments equal to the lesser of 5% of gross sales or $100,000 per annum commencing 90 days after January 1, 2001. Due to the conversion of the Company into an oil and gas enterprise and the nascent stage of the SYNSORB technology, the AHFMR accepted a royalty payment of $18,550 during the third quarter of 2003 in exchange for a full release of Hawker from the terms of the technology commercialization agreement.

Risks and Uncertainties

The Company is engaged in the exploration, development, production and acquisition of crude oil and natural gas. This business is inherently risky and there is no assurance that hydrocarbon reserves will be discovered and economically produced. Financial risks associated with the petroleum industry include fluctuations in commodity prices, interest rates, and currency exchange rates along with the credit risk of the Company’s industry partners. Operational risks include reservoir performance uncertainties, competition, environmental and safety issues, and a complex and changing regulatory environment.

Hawker is taking steps to reduce its business risks by increasing the number of core areas it has and increasing the number of areas it operates. This will spread the operational risks over several areas, reducing the potential impact on Hawker of unfavourable operational issues that may occur at any one area. It will also enable Hawker to control the timing, direction and costs related to exploration and development activities. Environmental and safety risks are mitigated through compliance with provincial and federal environmental and safety regulations, by maintaining adequate insurance, and by adopting appropriate emergency response and safety procedures.

The Company manages commodity pricing uncertainties with a risk management program that encompasses a variety of financial instruments. These include forward sales contracts on natural gas production and financial sales contracts.

Year ended December 31, 2002 compared with Year ended December 31, 2001

At December 31, 2002 the Company’s cash and working capital positions were $289,000 and $412,000, respectively, compared at December 31, 2001 balances of $5,841,000 and ($4,725,000) respectively.

As at December 21, 2002 the Company had no long term or short term debt. At December 31, 2001 the current portion of long term debt of the Company was $5,910,000, all of which was repaid during 2002.

The Company’s primary source of liquidity during 2002 was the liquidation of its assets. In 2002 the Company sold 2,255,565 common shares of Oncolytics for net proceeds of $6,898,000 resulting in a gain on sale of $4,899,000. As at December 31, 2002 the Company did not hold any common shares of Oncolytics. During 2002 the Company attempted to dispose of both its manufacturing equipment and its manufacturing facility. Subsequent to December 31, 2002 the Company disposed of most of its manufacturing equipment through auction realizing proceeds, net of expenses, of approximately $900,000 and has listed its manufacturing building and related land for sale as commercial premises. The Company also holds miscellaneous intellectual property rights with respect to certain drug technologies, which it may license, dispose of or abandon. In February 2003 the Company received U.S.$230,000 for an exclusive license of certain of its patents regarding toxin binding sugars. No assurance can be given as to whether any assets can be disposed of or what, if any, proceeds can or will be received with respect thereto.

In addition to the liquidation of assets, the Company may receive milestone payments and royalties with respect to the previous sale of its INH subsidiary or may choose to sell these rights. The Company cannot predict the likelihood, timing or amount of any milestone or royalty receipts.

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C. Research and development, patents and licenses, etc.

During 2001 and the previous two years, the research and development costs of the Company were expensed as incurred. Under Canadian GAAP, development costs should be capitalized if certain criteria are met. Companies with major products in clinical trials do not necessarily meet these criteria. In the United States all research and development costs are expensed in accordance with U.S. GAAP. The Company’s development costs in 2001, and the previous two years, did not meet the following two capitalization criteria: (i) the technical feasibility of the product or process must have been established; and (ii) the future market for the product or process must be clearly defined. With regard to (i), the Company was conducting clinical trials for SYNSORB Cd^® and SYNSORB Pk^® and the technical feasibility of these products was not known. With regard to (ii), the future market for these products was not clearly defined. For these reasons, the Company’s development costs were expensed and not capitalized.

D. Trend information.

There are no trends not already detailed in this annual report that the Company is aware of at this time that may impact the business or future prospects of the Company.

E. Off-balance sheet arrangements.

We have not entered into any transactions, arrangements or other relationships with unconsolidated, limited purpose entities.

F. Tabular disclosure of contractual obligations.

Forward Contracts

Pursuant to the exercise of the option to purchase an undivided interest of up to 49% in the Southward Properties, the Company acquired an interest in forward sales contracts and financial hedging contracts with respect to production from the Southward Properties. Such contracts represent 7,645 GJ/d of natural gas as follows:


Transaction Type	Volume (GJ/d)	Contract Price (GJ/d)		Expiry
Costless Collar	4,830	$	6.36 - $7.15	March 31, 2004
Fixed	1,610	$	6.76	March 31, 2004
Cogeneration Fuel Supply	263	$	1.959 - $2.217	October 31, 2008
Daily Declining Profile(1)	841	Netback⁽²⁾		October 31, 2011
Reserve Based	101	Netback⁽³⁾		Life of reserves

Notes:

(1) The Company’s obligation under this contract will, on November 1 of each succeeding year, decline to the following:


Date	Obligation (GJ/d)
November 1, 2004		724
November 1, 2005		623
November 1, 2006 and thereafter		568

(2) TransCanada Pipelines Limited netback pricing.

(3) Progas Limited netback pricing.

Following December 31, 2003, the Company entered into financial hedging contracts in respect of 28,000 GJ/d of natural gas as follows:


Transaction Type	Volume (GJ/d)		AECO Price (GJ/d)	Term
Collar		5,000	$5.50 - $6.35	April 1, 2004 to October 31, 2004
Collar		8,000	$5.50 - $6.40	April 1, 2004 to October 31, 2004
Collar		5,000	$5.50 - $6.36	April 1, 2004 to October 31, 2004
Fixed Price Swap		5,000	$5.745	April 1, 2004 to June 30, 2004
Fixed Price Swap		5,000	$5.745	August 1, 2004 to October 31, 2004
Fixed Price Swap		5,000	$5.7725	April 1, 2004 to October 31, 2004

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The Company has sufficient production to meet these commitments.

Item 6. Directors, Senior Management and Employees

A. Directors and senior management.

The following are the directors and officers of the Company, their municipality of residence, their positions with the Company and the periods during which each has served in such capacity, their principal occupations within the past five years, and the number and percentage of Common Shares owned or controlled by them.


			Number and Percentage of
			Common Shares
Name and Municipality of	Position with the		Beneficially Owned or
Residence	Company	Principal Occupation For Past Five Years	Controlled⁽¹⁾
David A. Tuer	President and Chief	President and Chief Executive Officer and a	825,466 (2.01%)
Calgary, Alberta	Executive Officer and a Director since January 6, 2003	Director of Hawker. Prior to October 2001, President, Chief Executive Officer and a Director of PanCanadian Petroleum Limited

Ronald P. Mathison	Chairman and a	President of Matco Investments Ltd. (a private	3,832,786 (9.34%)⁽²⁾
Calgary, Alberta	Director since April 3, 2003	investment company). Prior to 1999, Principal, Peters & Co. Limited

Stan G.P. Grad	Director since April	Independent Businessman	47,050 (0.11%)
Calgary, Alberta	21, 2003

Bruce J. Kenway, C.A.	Director since	Partner, Kenway Mack Slusarchuk Stewart LLP,	70,637 (0.17%)
Calgary, Alberta	March 31, 1994	Chartered Accountants

Martin A. Lambert	Director since April	Partner, Bennett Jones LLP (a law firm). Prior to	54,400 (0.13%)⁽³⁾
Calgary, Alberta	3, 2003	May 2000, Chief Executive Officer and a Partner, Bennett Jones LLP

Keith T. Smith	Director since April	President and Chief Executive Officer of zed.i	22,575 (0.06%)
Calgary, Alberta	3, 2003	solutions inc. from April 2001. Prior thereto, Vice President, Corporate Development with zed.i solutions inc. since April 2000 and Executive Vice President of Acanthus Resources Ltd., a private oil and gas company, from August 1998 to April 2000. Prior thereto, Executive Vice President of WestCastle Energy Corp., the Manager of WestCastle Energy Trust, and a Director of WestCastle Acquisition Corp., the operating company of WestCastle Energy Trust from February 1997 to August 1998

Barry R. Herring	Chief Financial	Chief Financial Officer of the Company since	40,725 (0.10%)⁽⁴⁾
Calgary, Alberta	Officer since May 6, 2003	May 6, 2003. Prior thereto, Vice President, Finance and Chief Financial Officer of Southward Energy Ltd. from January 2002 to April 2003, Senior Vice President of Calpine Canada from June 2000 to September 2000, Vice President, Finance and Operations of Quintana Minerals Canada Corp. from May 1999 to June 2000 and Vice President, Finance and Operations of Ocean Energy Inc. from 1997 to 1999.

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			Number and Percentage of
			Common Shares
Name and Municipality of	Position with the		Beneficially Owned or
Residence	Company	Principal Occupation For Past Five Years	Controlled⁽¹⁾
Terry C. Schmidtke	Chief Operating	Chief Operating Officer of the Company since	62,750 (0.15%) ⁽⁵⁾
Calgary, Alberta	Officer since April 21, 2003	April 21, 2003. Prior thereto, Senior Vice President, Central Plains Region for EnCana Company from April 2002 to March 2003, and General Manager of various business units of PanCanadian Petroleum Limited since 1994.

Darrell R. Peterson	Corporate Secretary	Partner, Bennett Jones LLP (a law firm) since	3,575 (0.01%)
Calgary, Alberta	since April 3, 2003	March 2003. Prior thereto, Associate of Bennett Jones LLP

Notes:

(1) Information as to Common Shares beneficially owned, not being within the knowledge of the Company, has been furnished by the respective officers and directors.

(2) Of these Common Shares, 3,641,286 are owned by Matco Capital Ltd. Matco Capital Ltd. is controlled by Matco Investments Ltd. and Matco Investments Ltd. is controlled by Ronald Mathison. To the knowledge of the Company, the only entities with an interest of greater than 10% in Matco Capital Ltd. are Matco Investments Ltd. and Mountain Moon Capital Inc. To the knowledge of the Company, the only shareholder holding, directly or indirectly, greater than 10% of the outstanding shares of Matco Investments Ltd. is Ronald Mathison and the only shareholders holding, directly or indirectly, greater than 10% of Mountain Moon Capital Inc. are members of Martin Lambert’s immediate family. In addition to his beneficial ownership of Common Shares resulting from his control of Matco Investments Ltd., Mr. Mathison beneficially owns 13,900 Common Shares as a result of shared power to dispose of such shares.

(3) Excludes 3,641,286 Common Shares held by Matco Capital Ltd. Matco Capital Ltd. is controlled by Matco Investments Ltd. and Matco Investments Ltd. is controlled by Ronald Mathison. To the knowledge of the Company, the only entities with an interest of greater than 10% in Matco Capital Ltd. are Matco Investments Ltd. and Mountain Moon Capital Inc. To the knowledge of the Company, the only shareholder holding, directly or indirectly, greater than 10% of the outstanding shares of Matco Investments Ltd. is Ronald Mathison and the only shareholders holding, directly or indirectly, greater than 10% of Mountain Moon Capital Inc. are members of Martin Lambert’s immediate family.

(4) Does not include options to acquire 100,000 Common Shares held by this individual.

(5) Does not include and options to acquire 75,000 Common Shares held by this individual.

B. Compensation.

Compensation of Executive Officers

The following table presents, for the most recently completed financial year of the Company, the remuneration of the executive officers in place (collectively, the “Named Executive Officers”). No other executive officer of the Company received a combined salary and bonus of more than $100,000 in the fiscal year ended December 31, 2003.

Long-Term

Annual Compensation

Compensation

Common

Shares Under

Other Annual

Options

All Other

Name and Principal

Salary

Bonus

Compensation⁽¹⁾

Granted

Compensation

Position

Year

($)

(#)

($)

David A. Tuer⁽²⁾

2003

175,000

135,000

17,625

—

President and Chief Executive Officer

Jim Silye⁽³⁾

2003

—

⁽⁴⁾

—

President and Chief Executive Officer

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Long-Term

Annual Compensation

Compensation

Common

Shares Under

Other Annual

Options

All Other

Name and Principal

Salary

Bonus

Compensation⁽¹⁾

Granted

Compensation

Position

Year

($)

(#)

($)

Barry R. Herring

2003

100,000

60,000

11,122

100,000

—

Senior Vice President, Finance and Chief Financial Officer

Terry Schmidtke

2003

100,000

60,000

10,732

75,000

—

Senior Vice President, Operations and Chief Operating Officer

Joe Straka

2003

90,000

⁽⁵⁾

—

6,519

50,000

—

Director, Exploration

Notes:

(1) The value of perquisites and benefits for each Named Executive Officer is less than the lesser of $50,000 and 10% of total annual salary and bonus.

(2) Appointed Chief Executive Officer on January 6, 2003.

(3) Appointed President and Chief Executive Officer on May 7, 2002. Terminated employment as Chief Executive Officer on January 6, 2003, and terminated employment as President on April 3, 2003.

(4) A corporation controlled by Mr. Silye received $94,577 for consulting services from the period of January 2003 to the end of June 2003.

(5) A corporation controlled by Mr. Straka received $32,807 for consulting services provided to the Company prior to Mr. Straka’s appointment as Director, Exploration.

The following table details information with respect to the grant of options by the Company to the Named Executive Officers during the fiscal year of the Company ended December 31, 2003.


								Market Value of
								Common Shares
			% of Total Options					Underlying Options
			Granted to			Exercise or Base		on the Date of
	Common Shares Under		Employees in			Price		Grant
Name	Options Granted		Financial Year			($/Common Share)		($/Common Share)		Expiration Date
David A. Tuer		—		—			—		—		—
Jim Silye		—		—			—		—		—
Barry R. Herring		100,000		23.4	%	$	3.45	$	3.45	May 30, 2008
Terry C. Schmidtke		75,000		17.5	%	$	3.45	$	3.45	May 30, 2008
Straka		50,000		11.7	%	$	3.90	$	3.90	July 1, 2008

Notes:

(1) Pursuant to the material terms of the Company’s stock option plan (the “Stock Option Plan”) under which the options were granted, the exercise price is not less than the closing market price on The Toronto Stock Exchange (“TSX”) on the day preceding the grant and are exercisable after one year as to one-third per year plus the portion of the optioned shares which could have been exercised in a previous year.

(2) The securities under option represent Common Shares.

The following table details information with respect to all options of the Company exercised by Named Executive Officers during the last fiscal year of the Company and all options held by Named Executive Officers and outstanding on December 31, 2003.

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Value of

Unexercised Options

Unexercised in the

at Financial

Money Options at

Common Shares

Year-End

Financial Year End

Acquired on

Aggregate Value

Exercisable/unexerci-

Exercise

Realized

sable

Name

(#)

($)

($)⁽¹⁾

David A. Tuer

—

—/—

—

Jim Silye

75,000

142,750

—/—

—

Barry R. Herring

—

—/100,000

—/$165,000

Terry C. Schmidtke

—

—/75,000

—/$123,750

Joe Straka

—

—/50,000

—/$60,000

Employment Agreements

Pursuant to an employment agreement dated as of April 3, 2003, Mr. Tuer is entitled to an annual base salary of $175,000 per year and to a discretionary bonus of up to a maximum of 200% of his base salary as determined by the board of directors of the Company in light of the Company’s overall operational and financial performance. In the event Mr. Tuer is terminated other than for cause, he is entitled to a payment equal to his annual base salary at the date of termination multiplied by 1.5 and his average bonus entitlement for the two preceding years multiplied by 1.5. Mr. Tuer’s salary is effective from January 6, 2003, the date he became the Chief Executive Officer of the Company.

Compensation of Directors

During the fiscal year ended December 31, 2003, no director’s fees were paid.

Directors of the Company are eligible to receive stock options. During 2003, no options were granted to directors.

C. Board practices.

Directors are elected annually to the Board at the annual meeting of the shareholders of the Company. No Director has a service contract with the Company.

Duties and Obligations of the Board of Directors

The general duty of the Board of Directors of the Company is to oversee the management of the business and affairs of the Company. In particular, the Board of Directors is responsible for the following matters:

(a) adopting a strategic planning process for the Company which establishes the Company’s long-term goals and strategies, and monitoring the success of the Company’s management in achieving those goals and implementing the strategy;

(b) identifying the principal risks with respect to all aspects of the Company’s business, ensuring that there are systems in place to effectively monitor and manage such risks with a view to the long-term viability of the Company, and achieving a proper balance between the risks incurred and the potential return to the Company’s members;

(c) engaging in succession planning, including appointing, training and monitoring senior management (which includes ensuring that objectives are in place against which management’s performance can be measured), establishing and maintaining programs to train and develop management, providing for the orderly succession of management, and assessing the performance and contribution of the Chief Executive Officer of the Company against mutually established objectives;

(d) ensuring that the Company has a policy in place to enable it to communicate effectively with its shareholders, other stakeholders and the general public, effectively interpreting the operations of the Company to shareholders, accommodating feedback from shareholders, and ensuring that there are effective controls and information systems in place for the Board of Directors to discharge its responsibilities, such as an audit system which can inform the Board of Directors about the integrity of the data and the compliance of the financial information with appropriate accounting principles.

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Composition of the Board of Directors

The Board of Directors is currently composed of six persons: David Tuer, Ronald Mathison, Stan Grad, Bruce Kenway, Martin Lambert and Keith Smith. All of the directors other than Mr. Tuer and Mr. Mathison are considered by the Board to be unrelated directors. The Toronto Stock Exchange Guidelines describe an “unrelated director” as a director who is independent of management and is free from any interest and any business or other relationship which could, or could reasonably be perceived to, materially interfere with the director’s ability to act with a view to the best interests of the Company, other than interests and relationships arising from shareholdings. In determining whether a director is an unrelated director, the Board considers, for example, whether the director has a relationship that could, or could be perceived to, interfere with the director’s ability to objectively assess the performance of management. On this basis, Mr. Tuer, by reason of his office as Chief Executive Officer, and Mr. Mathison, by reason of his office as Chairman, are considered related directors.

The separation of the position of Chairman from the position of President and Chief Executive Officer further ensures that the Board maintains its independence from management.

Committees of the Board of Directors

There are currently four committees of the Board of Directors. The Audit Committee is comprised of three directors, two of whom are unrelated directors. The Corporate Governance Committee is comprised of two directors, one of whom is an unrelated director. The Reserves Committee and the Compensation Committee are comprised of two directors, both of whom are unrelated directors. The mandate and activities of each committee are as follows:

Audit Committee: The Audit Committee currently consists of Ronald Mathison, Bruce Kenway and Martin Lambert. The responsibilities of the Audit Committee include:

(a) assisting the directors with meeting their responsibilities with respect to financial reporting;

(b) reviewing and reporting to the Board of Directors on all audited financial statements prepared by the Company and enhancing the credibility and objectivity of all financial reports;

(c) reviewing with management and with the external auditor any proposed changes in major accounting policies, in the presentation and impact of significant risks and uncertainties, and in key estimates and judgments of management that may be material to financial reporting;

(d) questioning management and the external auditor regarding significant financial reporting issues discussed during the fiscal period and the method of resolution;

(e) reviewing any problems experienced by the external auditor in performing the audit, including any restrictions imposed by management or significant accounting issues on which there was a disagreement with management; and

(f) reviewing the post-audit or management letters containing the recommendations of the external auditor and management’s response, and following up any identified weaknesses.

Corporate Governance Committee: The Corporate Governance Committee currently consists of Ronald Mathison and Martin Lambert. The Corporate Governance Committee assists the Board of Directors in discharging its corporate governance obligations. The responsibilities of the Corporate Governance Committee include considering the appropriate size and composition of the Board of Directors and its committees, establishing director selection criteria, reviewing credentials of nominee directors, making recommendations relative to the composition of the committees, reviewing the effectiveness of the Board of Directors’ operations and its relations with management, and assessing the performance of the directors including, the Chairman of the Board of Directors.

Reserves Committee: The Reserves Committee currently consists of Stan Grad and Keith Smith. The responsibilities of the Reserves Committee are to assist the Board of Directors in respect of annual independent evaluations of the Company’s petroleum and natural gas reserves. In that regard, the Reserves Committee has the authority and responsibility for reviewing and reporting to the Board of Directors in respect of the appointment of independent consultants to assist the Company in the annual evaluation of reserves and the scope of the annual evaluation of the reserves by the independent consultants. In addition, the Reserves Committee is responsible for meeting annually with the Company’s senior reserve personnel and the independent consultants of the Company to review and consider the evaluation of the Company’s petroleum and natural gas reserves and to address matters of concern related thereto.

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Compensation Committee: The Compensation Committee currently consists of Martin A. Lambert and Keith T. Smith. The Compensation Committee approves the compensation paid to the Company’s officers and in general the overall compensation paid by the Company to its employees.

Decisions Requiring the Prior Approval of the Board of Directors

Each committee of the Board of Directors makes recommendations to the Board on an ongoing basis. Generally, recommendations from a committee of the Board of Directors require the approval of the full Board before they are implemented.

D. Employees.

As at December 31, 2003, the Company had 14 full-time employees and retained 15 consultants. There has not been any significant change in the number of full-time employees over the last year.

E. Share ownership.

Information as to share and option information for directors, officers and key employees is discussed above in “Item 6. A. Directors and Senior Management” and in “Item 6. B. Compensation”.

Stock Option Plan

Hawker has an incentive option plan (the “Stock Option Plan”), the purpose of which is to develop the interests of the directors, officers, employees and other persons who provide on-going services to the Company in the growth and development of the Company by providing such individuals with the opportunity to acquire an increased proprietary interest in the Company and to aid in attracting as well as retaining and encouraging the continued involvement of such persons with the Company. The total number of shares issuable pursuant to the Stock Option Plan is 2,981,513 Common Shares, representing approximately 7.3% of the outstanding Common Shares as at June •30, 2004. The Company intends to maintain the number of Common Shares issuable pursuant to outstanding stock options at well under 10% of the number of outstanding Common Shares.

Under the Stock Option Plan, options may be issued to directors, officers, employees of, and other service providers to, the Company in such numbers and with vesting provisions as the Board may determine. The exercise price of options shall be the closing price of the Common Shares on the TSX on the first date preceding the date of grant on which the Common Shares traded on the TSX, and the maximum term for options under the Stock Option Plan is ten years.

The Stock Option Plan provides that if an optionee ceases to be a director, officer, or employee of, or service provider to, the Company or any of its subsidiaries for any reason (other than death), the optionee may exercise all of the vested options then held by the optionee, but only within 90 days after such cessation and prior to the normal expiry time. In the case of death of an optionee, all options of such optionee are deemed to have vested on the day immediately prior to the date of such optionee’s death, and the optionee’s legal personal representative shall have the right to exercise all or part of such options until the earlier of the date that is one year thereafter or the normal expiry time.

As at December 31, 2003, 444,001 options were outstanding with a weighted average exercise price of $4.74 and a weighted average remaining contractual life of 4.46 years. Subsequent to December 31, 2003, an aggregate of 414,200 options were issued with exercise prices ranging from $4.89 to $5.75 and expiry dates during the first six months of 2009. Subsequent to December 31, 2003, 15,000 options with an exercise price of $3.45 and an expiry date of May 30, 2008 were cancelled.

At the Annual and Special Meeting of Shareholders on April 28, 2004, shareholders approved an amendment to the Stock Option Plan to provide for a cash payment feature.

Item 7. Major Shareholders and Related Party Transactions

A. Major shareholders.

The following table sets forth information as of June 30, 2004, with respect to each person known to the Company to own more than 5% of the Common Shares. As used in this table, “beneficial ownership” means the sole or shared power to vote or direct the voting or to dispose or direct the disposition of any security. For purposes of this table, a person is deemed to be the beneficial owner of securities that can be acquired within 60 days from June 30, 2004, through the exercise of any option or warrant. Shares subject to options or warrants that are currently exercisable or

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exercisable within 60 days are deemed outstanding for computing the ownership percentage of the person holding such options or warrants, but are not deemed outstanding for computing the ownership percentage of any other person. None of the shareholders listed in the table below have voting rights that are different from other holders of Common Shares. The amounts and percentages are based upon 41,021,681 Common Shares issued and outstanding as of June 30, 2004.

Designation of

Type of

Shareholder

Class

Ownership

Number of Shares

% of Class

Ronald P. Mathison (1)

Common Shares

Note (2)

3,832,786

9.34

Allan P. Markin

Common Shares

Note (3)

3,812,678

9.29

Matco Capital (1)

Common Shares

Note (3)

3,641,286

8.88

Notes:

(1) Matco Capital Ltd. is controlled by Matco Investments Ltd. and Matco Investments Ltd. is controlled by Ronald Mathison. To the knowledge of the Company, the only entities with an interest of greater than 10% in Matco Capital Ltd. are Matco Investments Ltd. and Mountain Moon Capital Inc. To the knowledge of the Company, the only shareholder holding, directly or indirectly, greater than 10% of the outstanding shares of Matco Investments Ltd. is Ronald Mathison and the only shareholders holding, directly or indirectly, greater than 10% of Mountain Moon Capital Inc. are members of Martin Lambert’s immediate family.

(2) In addition to his beneficial ownership of Common Shares resulting from his control of Matco Investments Ltd., Mr. Mathison beneficially owns 13,900 Common Shares as a result of shared power to dispose of such shares.

(3) Legal and beneficial ownership.

Of the Common Shares issued and outstanding as of June 30, 2004, 40,663,829 were registered to Canadian residents (70 shareholders), 357,421 were registered to residents of the United States (21 shareholders), and 431 were registered to residents of foreign countries (4 shareholders).

To the best of the Company’s knowledge, the Company is not directly owned or controlled by another corporation, by any foreign government or by any natural or legal person.

B. Related party transactions.

There are no other related party transactions other than those described below.

During the year ended December 31, 2003 the Company paid $2,150,000 for legal and advisory services to a law firm, a legal partnership of which one of the directors is a member.

During the year ended December 31, 2002, the Company paid $214,000 to Scout Capital Company (“Scout”), a principal shareholder of the Company at the time of the payment, as reimbursement of Scout’s costs with respect to the Company’s annual general meeting, together with $34,000 to reimburse Scout for expenses incurred on behalf of the Company. Scout also received $50,000 pursuant to an agreement that expired on May 31, 2003 under which Scout was to provide the Company with certain administrative and executive services.

On April 3, 2003, the Company completed a private placement of 75,000 Common Shares for aggregate proceeds of $45,363.64 to Geoffrey Smith, the President and Chief Executive Officer of Scout.

On May 12, 2003 and June 25, 2003, the Company advanced $782,000 and $1,000,000, respectively, to Southward to fund ongoing working capital requirements.

There are potential conflicts of interest to which the directors and officers of the Company will be subject in connection with the operations of the Company. In particular, certain of the directors and officers of the Company are involved in managerial and/or director positions with other oil and gas companies whose operations may, from time to time, be in direct competition with those of the Company or with entities which may, from time to time, provide financing to, or make equity investments in, competitors of the Company. Conflicts, if any, will be subject to the procedures and remedies available under the Business Corporations Act (Alberta). The Business Corporations Act (Alberta) provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided by the Business Corporations Act (Alberta).

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C. Interests of experts and counsel.

Not applicable.

Item 8. Financial Information

A. Consolidated statements and other financial information.

Please see “Item 17. Financial Statements” for a list of the financial statements filed as part of this annual report.

Dividend Policy

B. Significant changes.

There have been no significant changes following the close of the last financial year up to the date of this annual report that are known to us that require disclosure in this annual report and for which disclosure was not made in this annual report.

Item 9. The Offer and Listing

A. Offer and listing details.

The issued and outstanding Common Shares of the Company (41,021,696 shares as of June 30, 2004) are listed and posted for trading on The Toronto Stock Exchange under the trading symbol “HKR.” The Common Shares are registered shares.

The following is a summary of the trading history (in Canadian dollars) of the Common Shares of the Company on the TSX for:

• the annual high and low market prices for the five most recent full financial years;

• the quarterly high and low market prices for the two most recent full financial years and any subsequent period; and

• the high and low monthly market prices for the most recent six months.


	High		Low
Year
Fiscal year ended December 31, 1999	$	4.20	$	1.75
Fiscal year ended December 31, 2000	$	15.00	$	1.15
Fiscal year ended December 31, 2001	$	2.56	$	0.47
Fiscal year ended December 31, 2002⁽¹⁾	$	2.00	$	0.26
Fiscal year ended December 31, 2003	$	5.50	$	0.73
Quarter
Fiscal year ending December 31, 2002
First Quarter	$	0.59	$	0.26
Second Quarter⁽¹⁾	$	2.00	$	0.35
Third Quarter	$	1.35	$	0.67
Fourth Quarter	$	0.87	$	0.56
Fiscal year ended December 31, 2003
First Quarter	$	3.48	$	0.73
Second Quarter	$	4.48	$	2.62
Third Quarter	$	5.50	$	3.80
Fourth Quarter	$	5.34	$	3.80

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	High		Low
Most Recent Six Months
January 2004	$	5.90	$	5.00
February 2004	$	5.80	$	5.14
March 2004	$	5.31	$	4.85
April 2004	$	5.42	$	4.85
May 2004	$	5.38	$	5.00
June 2004	$	5.10	$	4.75

Notes:

(1) On May 8, 2002, each former holder of Common Shares received one new Common Share for each eight cancelled shares they previously held.

B. Plan of distribution.

Not applicable.

C. Markets.

The Common Shares are listed for trading on The Toronto Stock Exchange. The Common Shares are not listed for trading on an exchange or in other markets other than The Toronto Stock Exchange.

D. Selling shareholders.

Not applicable.

E. Dilution.

Not applicable.

F. Expenses of the issue.

Not applicable.

Item 10. Additional Information

A. Share capital.

Not applicable.

B. Memorandum and Articles of Association

The Company was incorporated as 599386 Alberta Ltd. on February 14, 1994 under Certificate of Incorporation No. 20599386. On March 31, 1994, the Company amended and altered its Articles of Incorporation to change its name to SYNSORB Biotech Inc. Effective May 8, 2002: (i) each former holder of common shares received one new common share for each eight cancelled common shares they previously held; (ii) the stated capital of the Company was reduced in respect of the common shares of the Company by $59,896,000; and (iii) 4,000,235 common shares of Oncolytics Biotech Inc. held by the Company were distributed to its shareholders. By articles of amendment filed on April 3, 2003, the name of the Company was changed to Hawker Resources Inc. and a new class of non-voting equity shares was created. On December 30, 2003, each of Pointwest and its wholly-owned subsidiary, Myriad Company, and the Company amalgamated pursuant to the provisions of the Business Corporations Act (Alberta) under the name Hawker Resources Inc. On December 31, 2003, 1053639 Alberta Ltd., a wholly-owned subsidiary of the Company, and the Company amalgamated pursuant to the provisions of the Business Corporations Act (Alberta) under the name Hawker Resources Inc. On March 17, 2004, Zorin was wound-up into the Company, pursuant to the provisions of the Business Corporations Act (Alberta).

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The Company’s Articles of Incorporation, as amended and restated, are subject to all the provisions of the Business Corporations Act (Alberta) (the “ABCA”). The ABCA provides that a company incorporated under that Act has all the powers and capacities of a natural person. The ABCA further stipulates that a company must not carry on a business that its articles prohibit. Thus, the Company has the power and capacity of a natural person.

The following brief description of provisions of the ABCA, the Company’s amended and restated Articles of Incorporation and its by-laws does not purport to be complete and is subject in all respects to the provisions of the ABCA, the Company’s restated Articles of Incorporation and its by-laws.

Directors’ Conflicts of Interest

Section 120 of the ABCA requires every director of the Company who is, in any way, directly or indirectly, interested in a proposed material contract or transaction of the Company, to disclose the nature and extent of the director’s interest in writing or by requesting to have it entered in the minutes of the meeting of directors or of meetings of committees of directors.

The ABCA further provides that a director or officer of the Company who is required to disclose an interest may not vote on any resolution to approve the contract or transaction unless the contract or transaction, (i) is an arrangement by way of security for money lent to or obligations undertaken by the director, or a body corporate in which the director has an interest, for the benefit of the Company or an affiliate, (ii) relates primarily to the director’s or officer’s remuneration as a director, officer, employee or agent of the Company or an affiliate, (iii) is for indemnity or insurance for the director against liability incurred by the director or officer acting in his or her capacity as director or officer of the Company, or (iv) is with an affiliate.

Quorum

Pursuant to the Company’s by-laws, the quorum for the transaction of business at any meeting of its board of directors must consist of a majority of the directors holding office or such greater number of directors as the Company’s board determines. However, directors must not transact business at a meeting of the directors unless at least half of the directors present are Canadian residents. Notwithstanding the foregoing, directors may transact business at a meeting of the directors when less than half of the directors present are Canadian residents if:

(a) a Canadian resident director who is unable to be present approves in writing or by telephone or other communications facilities the business transacted at the meeting; and

(b) the number of Canadian resident directors present at the meeting, together with any Canadian resident director who gives his approval under clause (a), totals at least half of the directors present at the meeting.

Borrowing Powers

Section 2.01 of the Company’s bylaws provides that the banking business of the Company including, without limitation, the borrowing of money and the granting of security therefor shall be transacted with such bodies corporate or organizations as may from time to time be designated or authorized by the board of directors.

Pursuant to the Company’s Articles, its directors may without the authorization of its shareholders, borrow money on the credit of the Company, issue, re-issue, sell or pledge debt obligations of the Company, give a guarantee on behalf of the Company, mortgage, hypothecate, pledge or otherwise create a security interest in all or any of the property of the Company, owned or subsequently acquired, to secure any obligation of the Company. The Company’s directors may also, by resolution, delegate the borrowing powers referred to above to one of its directors, a committee of directors or one of its officers.

Directors

The number of directors shall be not less than one and not more than eleven. The number of directors may be determined from time to time by an ordinary resolution of the shareholders passed at a duly convened general meeting. A director is not required to own any shares of the Company to be qualified to serve as a director. A director is required to be at least 18 years of age but is not required to retire under any age-limit requirement.

Upon each annual meeting, all the directors are deemed to retire. The number of directors to be elected at any such meeting will be the number of directors then in office unless the directors or shareholders otherwise determine.

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If the shareholders remove any director before the expiration of his or her period of office and appoint another person in his or her place, that person so appointed shall hold office only during the remainder of the time that the director in whose place he or she is appointed would have held the office if he or she had not been removed. If the shareholders do not appoint another director to replace the removed director the vacancy may be filled by the directors.

The directors, or any committee of directors, may take any action required or permitted to be taken by them and may exercise any of the authorities, powers and discretions for the time being vested in or exercisable by them by way of a resolution either passed at a meeting at which a quorum is present or consented to in writing under the applicable section of the ABCA.

The directors may appoint a president, one or more vice-presidents, a secretary, a treasurer and other officers as determined by the board, including assistants to the officers so appointed. The directors may specify the duties of and delegate powers to manage the business and affairs of the Company to these officers. The Company may also appoint a chairman of the board, who must also be a director, and assign the powers and duties assigned to the managing director or president, under the by-laws, or other powers and duties.

Rights Attached to Shares

The following is a description of the rights, preferences, and restrictions attached to each class of the Company’s shares:

Common Shares

The holders of Common Shares are entitled to receive notice of, and to one vote per share at, every meeting of shareholders of the Company, to receive such dividends as the board of directors declares and to share equally in the assets of the Company remaining upon the liquidation of the Company after the creditors of the Company have been satisfied, subject to the prior rights of the preferred shares.

Preferred Shares

The preferred shares are issuable in series, with each series consisting of such number of shares and having such rights, privileges, restrictions and conditions as may be determined by the board of directors of the Company prior to the issuance thereof. With respect to the payment of dividends and the distribution of assets in the event of liquidation, dissolution or winding-up of the Company, whether voluntary of involuntary, the preferred shares are entitled to preferences over the Common Shares and any other shares ranking junior to the preferred shares and may also be given such other preferences over the Common Shares and any other shares ranking junior to the preferred shares as may be determined at the time of creation of each series.

Alteration of the Rights of Shareholders

No rights, privileges or restrictions attached to the shares of the Company may be altered except with the approval by special resolution passed by a majority of not less than two-thirds of the votes cast by shareholders who voted in respect of that resolution or signed by all the shareholders entitled to vote on that resolution.

There are no limitations in the Company’s charter on the rights of non-resident or foreign owners to hold Common Shares of the Company.

Shareholders’ Meetings

The ABCA requires the directors of the Company to call an annual meeting of shareholders not later than fifteen months after the last annual meeting. Every meeting, other than an annual meeting, shall be called a special meeting. The directors may, whenever they think fit, convene a special meeting.

A notice of the time and place of a meeting of shareholders must be sent not less than 21 days and not more than 50 days before the meeting. Notice of a meeting must specify the time and place of a meeting, and, in case of special business, the general nature of that business and the text of any resolution. The accidental omission to give notice of any meeting to, or the non-receipt of any notice by any of the shareholders entitled to receive notice does not invalidate any proceedings at that meeting.

The Company’s directors may fix a date that is not less than 21 days and not more than 50 days before the meeting as the record date for the determination of the shareholders entitled to notice of the meeting. If a record date is not fixed, the

- 44 -

record date must be the close of business on the date immediately preceding the date on which notice is given, or if notice is not given, the date on which the meeting is held.

All business that is transacted at a meeting of shareholders, with the exception of consideration of the financial statement and the auditor’s report thereon, fixing the number of directors, the election of directors and the appointment of the auditors, is deemed to be special business.

The Company’s Articles stipulate that business shall be conducted at any general meeting if there is quorum present at the opening of the meeting not withstanding that there ceases to be a quorum present throughout the meeting. A quorum is two shareholders entitled to vote or proxyholders thereof representing not less than 5% of the outstanding shares of the Company entitled to vote at the meeting.

The Articles stipulate that the Chairman of the Board, or in his absence, the President of the Company, or in his absence a Vice-President of the Company who is a shareholder, shall preside as chairman of every general meeting.

Unless the directors otherwise determine, the instrument appointing a proxyholder shall be deposited at a place specified for that purpose in the notice convening the meeting, not less than forty-eight hours before the time for holding the meeting at which the proxyholder proposes to vote.

Notice of every general meeting should be sent to:

a) each director;

b) the auditor of the Company; and

c) every shareholder entered in the securities registrar as the holder of a share or shares carrying the right to vote at such meetings on the record date or, if no record date was established by the directors, on the date of mailing such notice.

No other person is entitled to receive notice of meetings of shareholders.

Change of Control

Except for the restrictions set out above that attach to the Company’s shares, there are no provisions in the Company’s Articles or other constituent documents that would delay, defer or prevent a change of control and that would operate only with respect to a merger, acquisition or corporate restructuring involving the Company.

Shareholder Ownership Disclosure

The Company’s by-laws do not contain provisions that govern an ownership threshold above which its shareholder ownership must be disclosed. However, the Company is governed by the Securities Act (Alberta) and under that Act, a person or company that becomes an “insider” (as that term is defined in such Act), must file a report with the applicable securities commission disclosing any direct or indirect beneficial ownership or control or direction over the Company’s securities. An “insider” includes all of the Company’s directors and senior officers, every director or senior office of a company that is itself an insider of the Company, all its subsidiaries, any person or corporation that, beneficially owns, directly or indirectly, voting securities of the Company, exercises control or direction over its voting securities, or beneficially owns, directly or indirectly, certain voting securities of the Company and exercises control or direction over certain voting securities of the Company that carry more than 10% of the voting rights attached to all of its voting securities, excluding voting securities held by a person or company as underwriter in the course of a distribution.

Capital Changes

The Company’s Articles and other constituent documents do not contain provisions that govern changes in its capital that are more stringent than those required by Canadian securities laws.

C. Material contracts.

Other than contracts entered into in the ordinary course of business, the Company has not entered into any other material contracts in the two years preceding this annual report that continue to exist.

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D. Exchange controls.

Except for the Investment Canada Act (Canada) and Canadian withholding taxes described below, there are no limitations on the right of non-residents of Canada or foreign owners to hold or vote the Common Shares or any of its other securities imposed by Canadian or provincial laws or any of its constating documents and there are no Canadian federal or provincial laws, decrees or regulations that restrict the export or import of capital or affect the remittance of dividends, interest or other payments to holders of any of the Company’s securities who are not residents of Canada.

E. Taxation.

The following summary of the material Canadian federal and U.S. federal income tax considerations generally applicable in respect of the holding or disposing of Common Shares is provided by the Company. This summary does not address all possible tax consequences relating to an investment in the Common Shares of the Company. There may be provincial, territorial, state and local taxes applicable to a potential shareholder, depending on the shareholder’s particular circumstances, which are not addressed in this summary. The tax consequences to any particular holder, including a U.S. Holder (defined below) 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 the holder is subject to taxation, the place where the holder is resident and generally, according to the holder’s particular circumstances.

United States Federal Income Tax Consequences

The following is a general discussion of certain material United States federal income tax consequences, under current law, generally applicable to a U.S. Holder (as hereinafter defined) of Common Shares of the Company. This discussion does not address all potentially relevant federal income tax matters and it does not address all of the tax consequences that may be relevant to a particular holder in light of the holder’s circumstances, or to persons subject to special provisions of federal income tax law, such as those described below. In addition, this discussion does not cover any state, local or foreign tax consequences. See “Canadian Federal Income Tax Consequences” below.

The following discussion is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, published Internal Revenue Service (“IRS”) rulings, published administrative positions of the IRS and court decisions that are currently applicable, any or all of which could be materially and adversely changed, possibly on a retroactive basis, at any time and which are subject to differing interpretations. This discussion does not consider the potential effects, both adverse and beneficial, of any proposed legislation which, if enacted, could be applied, possibly on a retroactive basis, at any time. This discussion is for general information only and it 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 United States federal income tax consequences to any such holder or prospective holder is made. Accordingly, holders and prospective holders of Common Shares of the Company should consult their own tax advisors about the federal, state, local, and foreign tax consequences of purchasing, owning and disposing of Common Shares of the Company.

U.S. Holders

As used herein, a “U.S. Holder” means a holder of Common Shares of the Company who is (i) a citizen or individual resident of the United States, (ii) a corporation or entity treated as a corporation for United States federal income tax purposes that is created or organized in or under the laws of the United States or of any political subdivision thereof, (iii) an estate whose income is taxable in the United States irrespective of source or (iv) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust, or that has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person. This summary does not address the tax consequences to, and U.S. Holder does not include, persons subject to specific provisions of federal income tax law, such as tax-exempt organizations, qualified retirement plans, individual retirement accounts and other tax-deferred accounts, financial institutions, insurance companies, real estate investment trusts, regulated investment companies, broker-dealers, persons or entities that have a “functional currency” other than the U.S. dollar, are subject to the alternative minimum tax, hold Common Shares as part of a straddle, hedging, conversion transaction, constructive sale or other arrangement, or who acquired their Common Shares through the exercise of employee stock options or otherwise as compensation for services. This summary is limited to U.S. Holders who own Common Shares as capital assets within the meaning of Section 1221 of the Code. If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds Common Shares, the tax treatment of a partner in the partnership generally will depend upon the status of the partner and the activities of the partnership. A beneficial owner of Common Shares that is a partner of a partnership holding Common Shares should consult its own tax advisor with respect to the tax consequences of the purchase, ownership and disposition of Common Shares. This summary does not address the consequences to a person of the ownership, exercise or disposition of any options, warrants or other rights to acquire Common Shares.

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Distribution on Common Shares of the Company

U.S. Holders receiving dividend distributions (including constructive dividends) with respect to Common Shares of the Company are required to include in gross income for United States federal income tax purposes the gross amount of such distributions, equal to the U.S. dollar value of such distributions on the date of receipt (based on the exchange rate on such date), to the extent that the Company has current or accumulated earnings and profits, without reduction for any Canadian income tax withheld from such distributions. Such Canadian tax withheld may be credited, subject to certain limitations, against the U.S. Holder’s federal income tax liability or, alternatively, may be deducted in computing the U.S. Holder’s federal taxable income by those who itemize deductions. See “Foreign Tax Credit” below. To the extent that distributions exceed current or accumulated earnings and profits of the Company, they will be treated first as a return of capital up to the U.S. Holder’s adjusted basis in the Common Shares and thereafter as gain from the sale or exchange of the Common Shares. Preferential tax rates for long-term capital gains are applicable to a U.S. Holder that is an individual, estate or trust. There are currently no preferential tax rates for long-term capital gains for a U.S. Holder that is a corporation.

Dividends that are received during a tax year beginning before January 1, 2009, by a U.S. Holder that is an individual, an estate or a trust will be taxed at the rates applicable to long-term capital gains (the current maximum rate is 15%), provided that such dividends are received from a “qualified foreign corporation” and the U.S. Holder meets certain holding period requirements. Under guidance published by the U.S. Treasury Department, a corporation organized under the laws of Canada, such as the Company, may be treated as a qualified foreign corporation in the event it is eligible for benefits under the double taxation treaty between the United States and Canada. A Canadian corporation in whose principal class of shares there is “substantial and regular trading” on a recognized securities exchange generally will be eligible for benefits of the treaty. The Company believes it currently satisfies this requirement, although there can be no assurance that it will continue to do so in the future.

Notwithstanding the foregoing, if the company constitutes a “foreign personal holding company,” a “foreign investment company,” or a “passive foreign investment company,” each as defined below, for its taxable year during which it pays a dividend, or for its immediately preceding taxable year, the company generally will not be treated as a “qualified foreign corporation” and dividends received by U.S. Holders that are individuals, estates or trusts will be subject to U.S. federal income tax at ordinary income tax rates (and not at the preferential tax rate applicable to long-term capital gains). As described below, the Company believes that it has qualified, and in the future may qualify, as a passive foreign investment company. Accordingly, dividends, if any, paid in a taxable year in which the Company is a passive foreign investment company or in the next taxable year would not qualify for the preferential capital gains tax rate even if the Company is eligible for the benefits of the U.S. – Canada Income Tax Treaty. At the present time, only limited guidance has been issued that would further clarify the application of these rules.

In the case of foreign currency received as a dividend that is not converted by the recipient into U.S. dollars on the date of receipt, a U.S. Holder will have a tax basis in the foreign currency equal to its U.S. dollar value on the date of receipt. Generally any gain or loss recognized upon a subsequent sale or other disposition of the foreign currency, including an exchange of such currency for U.S. dollars, will be ordinary income or loss. However, an individual whose realized gain does not exceed $200 will not recognize that gain, to the extent that there are no expenses associated with the transaction that meet the requirements for deductibility as a trade or business expense (other than travel expenses in connection with a business trip) or as an expense for the production of income.

Dividends paid on the Common Shares of the Company generally will not be eligible for the dividends received deduction allowed to corporations receiving dividends from certain United States corporations. A U.S. Holder that is a corporation and that owns shares representing at least 10% of the voting power and value of the Company may, under certain circumstances, be entitled to a 70% (or 80% if the U.S. Holder owns shares representing at least 20% of the voting power and value of the Company) deduction of the United States source portion of dividends received from the Company (unless the Company qualifies as a “foreign personal holding company” or a “passive foreign investment company,” as defined below). The availability of this deduction is subject to several complex limitations which are beyond the scope of this discussion.

Foreign Tax Credit

A U.S. Holder that pays (or has withheld from distributions) Canadian income tax with respect to the ownership of Common Shares of the Company may be entitled, at the option of the U.S. Holder, to either receive a deduction or a tax credit for such foreign tax paid or withheld. Generally, it will be more advantageous to claim a credit because a credit reduces United States federal income taxes on a dollar-for-dollar basis, while a deduction merely reduces the taxpayer’s income subject to tax. This election is made on a year-by-year basis and applies to all foreign taxes paid by (or withheld

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from) the U.S. Holder during that year. In addition, U.S. Holders which are corporations that own 10% or more of the voting stock of the Company may be entitled to a “deemed paid” foreign tax credit with respect to the payment of dividends by the Company under certain circumstances. There are significant and complex rules and limitations that apply to the foreign tax credit (including the deemed paid foreign tax credit) that are beyond the scope of this discussion. Because the availability of the foreign tax credit and the application of the limitations on the credit are fact specific, U.S. Holders of Common Shares of the Company should consult their own tax advisors regarding their particular circumstances.

Disposition of Common Shares of the Company

Subject to the discussion under “Passive Foreign Investment Company,” set forth below, a U.S. Holder generally will recognize capital gain or loss upon the sale or other disposition of Common Shares of the Company equal to the difference, if any, between (i) the amount of cash plus the fair market value of any property received, and (ii) the shareholder’s tax basis in the Common Shares of the Company. This gain or loss will be long-term capital gain or loss if the Common Shares of the Company are held for more than one year. Preferential tax rates apply to long-term capital gains of U.S. Holders that are individuals, estates or trusts. Certain significant limitations exist on the deductibility of capital losses by both corporations and individuals.

Information Reporting and Backup Withholding

Certain information reporting rules may apply with respect to distributions made by the Company or to the proceeds of the sale or other disposition of Common Shares of the Company, and backup withholding (currently at the rate of 28%) may apply unless the U.S. Holder provides the appropriate intermediary with a taxpayer identification number, certified under penalties of perjury, as well as certain other information or otherwise establishes an exemption from backup withholding. Any amounts withheld under the U.S. backup withholding tax rules will be allowed as a refund or a credit against the U.S. Holder’s United States federal income tax liability, provided the required information is furnished to the IRS.

Other Considerations

In the following circumstances, the above sections of this discussion may not describe the United States federal income tax consequences resulting from the holding and disposition of Common Shares.

Foreign Personal Holding Company

If at any time during a taxable year (i) more than 50% of the total combined voting power or the total value of the Company’s outstanding shares is owned, directly or indirectly (pursuant to constructive ownership rules), by five or fewer individuals who are citizens or residents of the United States and (ii) 60% (50% in some circumstances) or more of the Company’s gross income for such year consists of certain types of passive income (e.g. dividends, interest, royalties, certain gains from the sale of stock and securities, and certain gains from commodities transactions), the Company may be treated as a “foreign personal holding company.” In that event, U.S. Holders that hold Common Shares would be required to include in gross income for such year their allocable portions of such passive income to the extent the Company does not actually distribute such income. The Company does not believe that it currently qualifies as a foreign personal holding company. However, there can be no assurance that the Company will not be considered a foreign personal holding company for the current or any future taxable year.

Foreign Investment Company

If 50% or more of the total combined voting power or total value of the Company’s outstanding shares is held, directly or indirectly (pursuant to constructive ownership rules), by citizens or residents of the United States, U.S. partnerships or corporations or U.S. estates or trusts (as defined for United States federal income tax purposes), and the Company is found to be engaged primarily in the business of investing, reinvesting, or trading in securities, commodities, or any interest therein, it is possible that the Company may be treated as a “foreign investment company,” causing all or part of any gain realized by a U.S. Holder selling or exchanging Common Shares to be treated as ordinary income rather than capital gain. The Company does not believe that it currently constitutes a foreign investment company. However, there can be no assurance that the Company will not be considered a foreign investment company for the current or any future taxable year.

Controlled Foreign Company

If more than 50% of the total combined voting power of all classes of shares entitled to vote or the total value of the shares of the Company is owned, actually or constructively, by citizens or residents of the United States, U.S.

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partnerships or corporations, or U.S. estates or trusts (as defined for U.S. federal income tax purposes), each of which owns, actually or constructively, 10% or more of the total combined voting power of all classes of shares entitled to vote of the Company (a “United States Shareholder”), the Company could be treated as a controlled foreign corporation (“CFC”). The classification of the Company as a CFC would effect many complex results, including that United States Shareholders would generally (i) be treated as receiving a current distribution of the Company’s “Subpart F income” and (ii) also would be subject to current United States federal income tax on their pro rata shares of the Company’s earnings invested in “United States property.” If the Company is classified as both a “passive foreign investment company,” as described below, and a CFC, the Company generally will not be treated as a passive foreign investment company with respect to United States Shareholders. The Company does not believe that it currently constitutes as a CFC. However, there can be no assurance that the Company will not be considered a CFC for the current or any future taxable year.

Passive Foreign Investment Company

Special United States federal income tax rules apply to U.S. Holders of shares in a “passive foreign investment company” (“PFIC”). A PFIC is any non-U.S. corporation if, for any taxable year, either (i) 75% or more of its gross income is “passive income,” which includes interest, dividends and certain rents and royalties or (ii) 50% or more of the value, determined on the basis of a quarterly average of the Company’s assets in a taxable year, are held for the production of passive income. If a foreign corporation owns, directly or indirectly, at least 25% by value of the stock of a second corporation, then for purposes of the tests described above, the first corporation will be treated as owning a proportionate share of the assets of, and as receiving a proportionate share of the income of, the second corporation. The Company believes that it qualified as a PFIC for the fiscal year ended December 2000, may have qualified as a PFIC in prior years and may qualify as a PFIC in subsequent years. There can be no assurance that the Company’s determination concerning its PFIC status will not be challenged. U.S. Holders of Common Shares of the Company are urged to consult their tax advisors with respect to how the PFIC rules affect their tax situation.

A U.S. Holder who holds stock in a foreign corporation during any year in which such corporation is a PFIC is subject to United States federal income taxation under one of three alternative tax regimes.

Under the first alternative, provided the Company satisfies certain record keeping requirements, the U.S. Holder may elect to treat the Company as a qualified electing fund (“QEF”). A U.S. Holder that elects in a timely manner to treat the Company as a QEF (an “Electing U.S. Holder”) will be currently taxable, in each taxable year in which the Company qualifies as a PFIC, on his pro rata share of the Company’s ordinary earnings and net capital gain (which will be taxed to the Electing U.S. Holder at ordinary income and capital gains rates, respectively). These amounts are included in income by the Electing U.S. Holder in the taxable year in which the Company’s taxable year ends, regardless of whether such amounts are actually distributed.

The QEF election also allows the Electing U.S. Holder to (i) generally treat any gain realized on the disposition of his Company Common Shares (or deemed to be realized on the pledge of his shares) as capital gain; (ii) treat his share of the Company’s net capital gain, if any, as long-term capital gain instead of ordinary income; and (iii) either avoid interest charges resulting from PFIC status altogether, or make an annual election, subject to certain limitations, to defer payment of current taxes on his share of the Company’s annual realized net capital gain and ordinary earnings subject, however, to an interest charge. If the Electing U.S. Holder is not a corporation, such an interest charge would be treated as “personal interest” that is not deductible.

A QEF election, once made with respect to the Company, applies to the tax year for which it was made and to all subsequent tax years, unless the election is invalidated or terminated, or the IRS consents to revocation of the election. Nonetheless, there can be no assurance that the Company will be able to satisfy the record keeping requirements imposed on a QEF and thus that a U.S. Holder may be able to make an effective QEF election and treat the Company as a QEF for any year in which the Company satisfies the definition of a PFIC. U.S. Holders are urged to consult a tax advisor regarding the availability of and procedure for making an effective QEF election.

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If a U.S. Holder does not make a timely QEF election during a year in which it holds (or is deemed to have held) the Common Shares in question and the Company is a PFIC (a “Non-Electing U.S. Holder”), then special taxation rules under Section 1291 of the Code will apply to (i) gains realized on the disposition (or deemed to be realized by reason of a pledge) of his Company Common Shares and (ii) certain “excess distributions” (generally, distributions received in the current taxable year that are in excess of 125% of the average distributions received during the three preceding years or, if shorter, the U.S. Holder’s holding period) by the Company.

A Non-Electing U.S. Holder generally would be required to prorate all gains realized on the disposition of his Company Common Shares and all excess distributions on his Company Common Shares over the entire holding period for the Common Shares. All gains or excess distributions allocated to prior years of the U.S. Holder (other than years prior to the first taxable year of the Company during such U.S. Holder’s holding period and beginning after January 1, 1987 for which it was a PFIC) would be taxed at the highest tax rate for each such prior year applicable to ordinary income. The Non-Electing U.S. Holder also would be liable for interest on the foregoing tax liability for each such prior year calculated as if such liability had been due with respect to each such prior year. A Non-Electing U.S. Holder that is not a corporation generally must treat this interest charge as “personal interest” which is wholly nondeductible for federal income tax purposes. The balance of the gain or the excess distribution will be treated as ordinary income in the year of the disposition or distribution, and no interest charge will be incurred with respect to such balance.

If the Company is a PFIC for any taxable year during which a Non-Electing U.S. Holder holds Company Common Shares, then the Company will continue to be treated as a PFIC with respect to such Company Common Shares, even if it is no longer definitionally a PFIC. A Non-Electing U.S. Holder may terminate this deemed PFIC status by electing to recognize gain (which will be taxed under the rules discussed above for Non-Electing U.S. Holders) as if such Company Common Shares had been sold on the last day of the last taxable year for which it was a PFIC.

Under Section 1291(f) of the Code, the IRS has issued Proposed Treasury Regulations that, subject to certain exceptions, would treat as taxable certain transfers of PFIC stock by Non-Electing U.S. Holders that are generally not otherwise taxed, such as gifts, exchanges pursuant to corporate reorganizations, and transfers at death. Generally, in such cases the basis of the Company Common Shares in the hands of the transferee and the basis of any property received in the exchange for those Common Shares would be increased by the amount of gain recognized. Under the Proposed Treasury Regulations, an Electing U.S. Holder would not be taxed on certain transfers of PFIC stock, such as gifts, exchanges pursuant to corporate reorganizations, and transfers at death. The specific tax effects to the U.S. Holder and the transferee may vary based on the manner in which the Common Shares are transferred.

U.S. Holders that hold, actually or constructively, marketable stock (as specifically defined in the Treasury Regulations) of a foreign corporation that qualifies as a PFIC may elect to mark such stock to the market (a “mark-to-market election”). The Company believes that the Common Shares constitute marketable stock for purposes of the mark-to-market election. If such an election is made, such U.S. Holder will generally not be subject to the special taxation rules of Section 1291 discussed above. However, if the mark-to-market election is made by a Non-Electing U.S. Holder after the beginning of the holding period for the PFIC stock, then the Section 1291 rules will apply to certain dispositions of, distributions on and other amounts taxable with respect to the Company Common Shares. A U.S. Holder who makes the mark-to-market election will include in income for the taxable year for which the election was made an amount equal to the excess, if any, of the fair market value of the Common Shares of the Company as of the close of such tax year over such U.S. Holder’s adjusted basis in such Common Shares. In addition, the U.S. Holder is allowed a deduction for the lesser of (i) the excess, if any, of such U.S. Holder’s adjusted tax basis in the Common Shares over the fair market value of such shares as of the close of the tax year, or (ii) the excess, if any, of (A) the mark-to-market gains for the Common Shares in the Company included by such U.S. Holder for prior tax years, including any amount which would have been included for any prior tax year but for the Section 1291 interest on tax deferral rules discussed above with respect to Non-Electing U.S. Holders, over (B) the mark-to-market losses for shares that were allowed as deductions for prior tax years. A U.S. Holder’s adjusted tax basis in the Common Shares of the Company will be adjusted to reflect the amount included in or deducted from income as a result of a mark-to-market election. A mark-to-market election applies to the taxable year in which the election is made and to each subsequent taxable year, unless the Company Common Shares cease to be marketable, as specifically defined, or the IRS consents to revocation of the election. U.S. Holders should consult their tax advisor regarding the manner of making such an election.

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U.S. Holders of the Company are urged to consult a tax advisor with respect to how the PFIC rules affect their tax situation.

Canadian Federal Income Tax Considerations

The following is a summary of the principal Canadian federal income tax consequences generally applicable to a holder of one or more Common Shares who, for the purposes of the Income Tax Act (Canada) (the “Tax Act”) at all relevant times, is a non-resident of Canada, holds the Common Shares as capital property (other than capital property used in or held in connection with a business being carried on in Canada) and deals at arm’s length with the Company (a “Holder”). This summary does not address the special tax consequences which may apply to a Holder who is an insurer carrying on an insurance business in Canada and elsewhere for the purposes of the Tax Act.

This summary is based on the current provisions of the Tax Act and the regulations thereunder and the provisions of the Canada-U.S. Income Tax Convention, 1980 (the “Treaty”), an understanding of the current administrative practices of the Canada Revenue Agency, and all specific proposals to amend the Tax Act and the regulations thereunder announced by or on behalf of the Canadian Minister of Finance prior to the date hereof, although there is no certainty that such proposals will be enacted in the form proposed, if at all. This summary does not otherwise take into account or anticipate any changes in law, whether by judicial, governmental or legislative decision or action, nor does it take into account tax legislation or considerations of any province or territory of Canada or any jurisdiction outside Canada.

This summary is of a general nature only, and does not constitute legal or tax advice to any particular Holder and no representation is made with respect to the tax consequences to any particular holder. Consequently, Holders should consult with their own tax advisors with respect to their particular circumstances.

Dividends

A Holder will be subject to Canadian withholding tax at the rate of 25%, or such lower rate as may be available under an applicable tax treaty, on the gross amount of any dividends paid or credited (or deemed to be paid or credited) on the Common Shares. By virtue of the Treaty, the rate of any such Canadian withholding tax on dividends paid or credited (or deemed to be paid or credited) to a resident of the United States for the purposes of the Treaty which is the beneficial holder thereof will generally be reduced to 15%, subject to a further reduction to 5% in the case of a U.S. corporate shareholder which owns 10% or more of the outstanding Common Shares of the Company.

Disposition of Common Shares

A Holder who disposes of Common Shares, including by deemed disposition on death or otherwise, will not be subject to Canadian tax under the Tax Act on any resulting capital gain unless the Common Shares constitute “taxable Canadian property” to the Holder. In general, Common Shares will only constitute taxable Canadian property to a Holder if the Common Shares are not listed on a prescribed stock exchange (which includes The Toronto Stock Exchange) or, at any time within the five-year period immediately preceding the disposition, the Holder, persons with whom the Holder did not deal at arm’s length, or the Holder together with such persons owned or had an interest in or the right to acquire more than 25% of the shares of any class or series of the capital stock of the Company.

A Holder who is a resident of the United States for the purposes of the Treaty and realizes a capital gain on a disposition or deemed disposition of Common Shares that constitute taxable Canadian property to the Holder will only be subject to Canadian tax if the Common Shares derive their value principally from real property situated in Canada. For this purpose, the definition of real property generally includes rights to explore for natural resources and rights to amounts computed by reference to the amount or value of production from such natural resources. The Company is of the view that the value of its Common Shares is currently derived principally from real property situated in Canada however, the determination as to whether Canadian tax would be applicable must be made at the time of the disposition or deemed disposition.

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F. Dividends and paying agents.

Not applicable.

G. Statement by experts.

Not applicable.

H. Documents on display.

We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and we file reports and other information with the SEC. You may read and copy any of our reports and other information at, and obtain copies upon payment of prescribed fees from, the Public Reference Room maintained by the SEC at 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549. In addition, the SEC maintains a Web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

We are required to file reports and other information with the securities commission in all provinces of Canada. You are invited to read and copy any reports, statements or other information, other than confidential filings, that we file with the provincial securities commissions. These filings are also electronically available 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.

We will provide without charge to each person, including any beneficial owner, on the written or oral request of such person, a copy of any or all documents referred to above which have been or may be incorporated by reference in this report (not including exhibits to such incorporated information that are not specifically incorporated by reference into such information). Requests for such copies should be directed to the Company’s principal executive offices at 700, 700 – 2nd Street S.W., Calgary, Alberta, T2P 2W1.

I. Subsidiary information.

The Company owns all of the issued and outstanding shares of Mar Oil Company, incorporated in the state of Delaware.

Item 11. Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to cash flow and translation risk due to changes in the Canadian/United States dollar exchange rate and interest rate fluctuations.

The information below about the foreign exchange and interest rate sensitivity constitutes a “forward looking statement.” The Company’s foreign exchange rate and interest exposure is due to the changing exchange rate between the Canadian and United States dollar and fluctuations in interest rates in Canada.

Exposure to exchange rate fluctuations are due to the translation of a portion of the Company’s cash balances, revenues and payables and direct costs.

As at December 31, 2003, the Company estimates that a $0.01 decrease in the value of the Canadian dollar relative to the United States dollar would have an annualized impact of reducing earnings from operations before taxes by $20,000.

The Company is exposed to interest rate risk relating to any debt pursuant to a revolving credit facility. The Company does not currently draw on this facility but does expect to draw on this facility to fund the exercise of the Purchase Option. The Company is also exposed to interest rate risk relating to cash balances. The Company’s policy is to deposit surplus cash in treasury accounts at a major Canadian chartered bank. These accounts earn interest at bank or money market rates in effect at such time.

Item 12. Description of Securities Other than Equity Securities

Not applicable.

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PART II

Item 13. Defaults, Dividend Arrearages and Delinquencies

None.

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds

None.

Item 15. Controls and Procedures

As of the end of the period covered by this Annual Report on Form 20-F, the Company conducted an evaluation (under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and Chief Financial Officer), pursuant to Rule 13a-15 promulgated under the Exchange Act, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of our evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in all material respects to ensure that information required to be disclosed in the reports the Company files and submits under the Exchange Act is recorded, processed, summarized and reported as and when required.

There were no significant changes in the Company’s internal controls or in other factors that have materially affected or which could materially affect the Company’s internal controls subsequent to the date the Company carried out its evaluation.

Pointwest was acquired by the Company on December 30•, 2003. Due to the significance of this acquisition, the financial statements of Pointwest as of and for the years ended December 31, 2001, 2002 and 2003 are included in this annual report. The financial statements of Pointwest for these periods were audited in accordance with Canadian generally accepted auditing standards; however, such financial statements were not audited in accordance with United States generally accepted auditing standards because Pointwest has never been a registrant under the Securities Exchange Act of 1934.

Item 16A. Audit Committee Financial Expert

Our Board of Directors has determined that Bruce Kenway qualifies as an audit committee financial expert serving on our audit committee.

Item 16B. Code of Ethics

The Company has adopted a code of business conduct and a corporate disclosure policy, both of which apply to the Company’s Chief Executive Officer, Chief Financial Officer and Controller. A copy of the code and the policy are available, without charge and upon request from the Assistant Corporate Secretary of the Company at the Company’s head office address.

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Item 16C. Principal Accountant Fees and Services

Ernst & Young LLP has served as our independent public accountants for the years ended December 31, 2002 and December 31, 2003. The following table summarizes the aggregate fees for professional audit services and other services rendered by Ernst & Young LLP in the past two years.

In Canadian dollars


	2002		2003
Audit Fees	$	36,583	$	66,900
Audit-Related Fees		12,655		44,600
Tax		7,770		1,998
All Other Fees		22,664		206,323

Total		79,672		319,821

Audit Fees

Audit fees include fees for professional services rendered in connection with the audit of our annual financial statements set forth in our Annual Report on Form 20-F and services provided by the audit of our annual financial statements set forth in our Annual Report on Form 20-F and services provided by the independent auditors in connection with statutory and regulatory filings or engagements.

Audit Related Fees

Audit-related fees are generally fees billed for services that are closely related to the performance of the audit or review of financial statements.

Tax Fees

Tax fees are fees for professional services rendered related to tax compliance, tax advice and tax planning.

All Other Fees

The Company’s audit committee is required to pre-approve all audit and non–audit services rendered by and approve the engagement fees and other compensation to be paid to the independent accountant and its affiliates. When deciding whether to approve these items, our audit committee takes into account whether the provision of any non-audit service is compatible with the independence standards under the guidelines of the SEC and of the Independent Standards Board. To assist in this undertaking, the audit committee requires the independent accountant to submit a report describing all relationships the independent accountant has with the Company and relevant third parties to determine the independent accountant’s independence.

The audit committee recommends to the Board the delegation to one or more designated members of the audit committee the authority to grant pre-approvals for audit and non-audit services. The decision of any member to whom the authority is delegated must be presented to the full audit committee.

The audit committee has approved all engagements listed above.

All of the hours spent on the audit were done by Ernst & Young LLP.

Item 16D. Exemptions from the Listing Standards for Audit Committees

Not applicable

Item 16E. Purchases of Equity Securities by the Issuer and affiliated purchases

Not applicable.

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PART III

Item 17. Financial Statements

The financial statements attached to this document were prepared in accordance with Canadian GAAP and are presented in Canadian dollars. There are differences between U.S. GAAP and Canadian GAAP. The reconciliation of the financial statements to the United States GAAP is set forth in the notes to the financial statements.

The following financial statements are filed as part of this annual report, together with the report of the auditors:


	Page
Compilation Report on Pro Forma Financial Statements of Ernst & Young LLP dated December 19, 2003		F-2
Unaudited Pro Forma Consolidated Balance Sheet of Hawker as at September 30, 2003		F-3
Unaudited Pro Forma Consolidated Statement of Earnings of Hawker for the nine months ended September 30, 2003 and year ended December 31, 2002		F-5
Notes to the Unaudited Pro Forma Consolidated Financial Statements as at September 30, 2003 and for the nine months ended September 30, 2003 and year ended December 31, 2002		F-7
Audit Report of KPMG LLP dated April 12, 2003 (except for note 11 as to which the date is December 12, 2003)		F-10
Consolidated Balance Sheets of Pointwest as at September 30, 2003 and December 31, 2002 and 2001		F-11
Consolidated Statements of Operations and Retained Earnings (Deficit) of Pointwest for the nine month periods ended September 30, 2003 and 2002, years ended December 31, 2002 and 2001, and period from July 25, 2000 to December 31, 2000		F-12
Consolidated Statements of Cash Flows of Pointwest for the nine month periods ended September 30, 2003 and 2002, years ended December 31, 2002 and 2001, and period from July 25, 2000 to December 31, 2000		F-13
Notes to the Consolidated Financial Statements of Pointwest as at September 30, 2003 and December 31, 2002, 2001 and 2000.		F-14
Audit Report of Ernst & Young LLP dated March 10, 2004 (except for note 17, which is as of March 17, 2004)		F-23
Audited Balance Sheets of Hawker as at December 31, 2003 and December 31, 2002		F-24
Audited Statements of Earnings (Loss) and Deficit of Hawker for the years ended December 31, 2003, 2002 and 2001		F-25
Audited Statements of Cash Flows of Hawker for the years ended December 31, 2003, 2002 and 2001		F-26
Notes to the December 31, 2003, 2002 and 2001 audited Financial Statements of Hawker		F-27
Audit Report of Deloitte & Touche LLP dated April 21, 2003		Note 1
Audited Statements of Revenues and Operating Expenses relating to the proposed acquisition by Hawker of the Optioned Properties for each of the years ended December 31, 2002, 2001 and 2000		Note 1
Notes to the December 31, 2002, 2001 and 2000 audited Statements of Revenues and Operating Expenses		Note 1
Audit Report of Deloitte & Touche LLP dated March 17, 2003 Audited Consolidated Balance Sheets of Southward as at December 31, 2002 and December 31, 2001		Note 1
Audited Consolidated Statements of Operations and Retained Earnings of Southward for the years ended December 31, 2002, 2001 and 2000		Note 1
Audited Consolidated Statements of Cash Flows of Southward for the years ended December 31, 2002, 2001 and 2000		Note 1
Notes to the December 31, 2002, 2001 and 2000 audited Consolidated Financial Statements of Southward		Note 1

Note 1 – Previously filed by the Company

- 55 -

Item 18. Financial Statements

Not applicable.

Item 19. Exhibits

The following exhibits are filed as part of this annual report:


Exhibit
Number		Description
1.1⁽¹⁾		Articles of Incorporation of the Company dated February 14, 1994

1.2⁽¹⁾		Articles of Amendment of the Company dated March 31, 1994.

1.3⁽¹⁾		Articles of Amendment of the Company dated July 12, 1994.

1.4⁽¹⁾		Articles of Arrangement of the Company dated May 8, 2002.

1.5⁽¹⁾		Restated Articles of Incorporation of the Company dated May 8, 2002.

1.6⁽¹⁾		Articles of Amendment and Restated Articles of the Company dated April 3, 2003.

1.7⁽¹⁾		Articles of Amendment and Restated Articles of the Company dated April 3, 2003.

1.8		Articles of Amalgamation and Registration Statement of the Company dated December 30, 2003

1.9		Articles of Amalgamation and Registration Statement of the Company dated December 30, 2003

1.10		Articles of Amalgamation and Registration Statement of the Company dated December 31, 2003

1.11		Articles of Amendment and Restated Articles of the Company dated May 3, 2004

1.12⁽¹⁾		By-Law Number 1 of the Company dated March 31, 1994.

4.1⁽¹⁾		Stock Option Plan of the Company

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

Note:

(1) Previously filed by the Company.

- 56 -

Table of Contents — Financial Statements.


	Page
Compilation Report on Pro Forma Financial Statements of Ernst & Young LLP dated December 19, 2003		F-2
Unaudited Pro Forma Consolidated Balance Sheet of Hawker as at September 30, 2003		F-3
Unaudited Pro Forma Consolidated Statement of Earnings of Hawker for the nine months ended September 30, 2003 and year ended December 31, 2002		F-5
Notes to the Unaudited Pro Forma Consolidated Financial Statements as at September 30, 2003 and for the nine months ended September 30, 2003 and year ended December 31, 2002		F-7
Audit Report of KPMG LLP dated April 12, 2003 (except for note 11 as to which the date is December 12, 2003)		F-10
Consolidated Balance Sheets of Pointwest as at September 30, 2003 and December 31, 2002 and 2001		F-11
Consolidated Statements of Operations and Retained Earnings (Deficit) of Pointwest for the nine month periods ended September 30, 2003 and 2002, years ended December 31, 2002 and 2001, and period from July 25, 2000 to December 31, 2000		F-12
Consolidated Statements of Cash Flows of Pointwest for the nine month periods ended September 30, 2003 and 2002, years ended December 31, 2002 and 2001, and period from July 25, 2000 to December 31, 2000		F-13
Notes to the Consolidated Financial Statements of Pointwest as at September 30, 2003 and December 31, 2002, 2001 and 2000.		F-14
Audit Report of Ernst & Young LLP dated March 10, 2004 (except for note 17, which is as of March 17, 2004)		F-23
Audited Balance Sheets of Hawker as at December 31, 2003 and December 31, 2002		F-24
Audited Statements of Earnings (Loss) and Deficit of Hawker for the years ended December 31, 2003, 2002 and 2001		F-25
Audited Statements of Cash Flows of Hawker for the years ended December 31, 2003, 2002 and 2001		F-26
Notes to the December 31, 2003, 2002 and 2001 audited Financial Statements of Hawker		F-27

F-1

COMPILATION REPORT ON
PRO FORMA FINANCIAL STATEMENTS

To the Directors of Hawker Resources Inc.

We have read the accompanying unaudited pro forma consolidated balance sheet of Hawker Resources Inc. (the “Company”) as at September 30, 2003 and unaudited pro forma consolidated statement of earnings for the nine months then ended and for the year ended December 31, 2002, and have performed the following procedures:

1. Compared the figures in the columns captioned “Hawker Resources Inc.” to the unaudited consolidated financial statements of the Company as at September 30, 2003 and for the nine months then ended, and the audited financial statements of the Company for the year ended December 31, 2002, respectively, and found them to be in agreement.

2. Compared the figures in the columns captioned “Pointwest Energy Inc.” (“Pointwest”) to the unaudited consolidated financial statements of Pointwest as at September 30, 2003 and for the nine months then ended and the audited consolidated financial statements of Pointwest for the year ended December 31, 2002, respectively, and found them to be in agreement.

3. Compared the figures in the columns captioned “W4M Properties Acquired” to the unaudited statement of revenues and operating expenses for the six months ended June 30, 2003 and the audited statement of revenues and operating expenses for the year ended December 31, 2002, respectively, and found them to be in agreement.

4. Made enquiries of certain officials of the Company who have responsibility for financial and accounting matters about:

(a) the basis for determination of the pro forma adjustments; and

(b) whether the pro forma consolidated financial statements comply as to form in all material respects with applicable regulatory requirements.

The officials:

(a) described to us the basis for determination of the pro forma adjustments, and

(b) stated that the pro forma consolidated financial statements comply as to form in all material respects with applicable regulatory requirements.

5. Read the notes to the unaudited pro forma consolidated financial statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

6. Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the columns captioned “Hawker Resources Inc.”, “Pointwest Energy Inc.” and “W4M Properties Acquired” as at September 30, 2003 and for the nine months then ended, and for the year ended December 31, 2002, and found the amounts in the column captioned “Pro forma” to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management’s assumptions, the pro forma adjustments, and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma consolidated financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.


Calgary, Canada		(Signed) Ernst & Young LLP
December 19, 2003		Chartered Accountants

F-2

Hawker Resources Inc.

PRO FORMA CONSOLIDATED BALANCE SHEET
As at September 30, 2003
(Unaudited)


	Hawker			Pointwest
	Resources			Energy		Pro forma
	Inc.			Inc.		adjustments					Pro forma
[thousands of Canadian dollars]	$			$		$			Notes		$
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current
Accounts payable and accrued liabilities		10,314			12,599							22,913
Bank loan		—			5,250							5,250

		10,314			17,849		—					28,163
Bank loan		23,119			—		21,801			2(e)		40,406
							10,000			2(f)
							(14,514	)		2(g)
Leasehold inducements		140			—							140
Future income taxes		—			10,729		(10,729	)		2(b), 3		—
Future site restoration and abandonment costs		146			774							920

		33,719			29,352		6,558					69,629

Shareholders’ equity
Share capital		58,323			24,901		(24,901	)		2(b)		115,289
							42,452			2(d)
							14,514			2(g)
Retained earnings (deficit)		(10,361	)		8,043		(8,043	)		2(b)		(10,361	)

		47,962			32,944		24,022					104,928

		81,681			62,296		30,580					174,557

See accompanying notes to unaudited pro forma consolidated financial statements

On behalf of the Board:


(Signed) “David A. Tuer”		(Signed) “Ronald P. Mathison”

Director		Director

F-4

Hawker Resources Inc.

PRO FORMA CONSOLIDATED STATEMENT OF EARNINGS
For the nine months ended September 30, 2003
(Unaudited)


	Hawker			W4M			Pointwest
	Resources			Properties			Energy			Pro forma
[thousands of Canadian dollars except per	Inc.			Acquired			Inc.			adjustments					Pro forma
share amounts]	$			$			$			$			Notes		$
Revenue
Oil and natural gas sales		8,786			21,248			40,070								70,104
Royalties, net		(2,389	)		(5,757	)		(9,708	)							(17,854	)
Interest income		68			—			—								68
Other		382			—			—								382

		6,847			15,491			30,362								52,700

Expenses
Production		838			1,795			4,092								6,725
General and administrative		2,329			—			770								3,099
Interest		267			—			213			1,227			2(a,e,f,g)		1,707
Depletion and depreciation		4,196			—			11,475			10,297			2(c)		25,968
Site restoration		146			—			404								550

		7,776			1,795			16,954			11,524					38,049

Earnings (loss) before the following:		(929	)		13,696			13,408			(11,524	)				14,651
Lease abandonment expense		(322	)		—			—								(322	)
Operating costs and write-downs associated with assets held for sale		(179	)		—			—								(179	)
Alberta Heritage Foundation grant settlement		368			—			—								368

Earnings (loss) before income taxes		(1,062	)		13,696			13,408			(11,524	)				14,518
Income tax expense (recovery)		106			—			5,526			(5,393	)		3		239

Net earnings (loss)		(1,168	)		13,696			7,882			(6,131	)				14,279

Earnings per share *[note 4]*																0.36

See accompanying notes to unaudited pro forma consolidated financial statements

F-5

Hawker Resources Inc.

PRO FORMA CONSOLIDATED STATEMENT OF EARNINGS
For the year ended December 31, 2002
(Unaudited)


	Hawker			W4M			Pointwest
	Resources			Properties			Energy			Pro forma
[thousands of Canadian dollars except per	Inc.			Acquired			Inc.			adjustments					Pro forma
share amounts]	$			$			$			$			Notes		$
Revenue
Oil and natural gas sales		—			24,395			20,249								44,644
Royalties, net		—			(6,088	)		(4,701	)							(10,789	)
Interest income		32			—			27								59
Other		107			—			—								107

		139			18,307			15,575								34,021

Expenses
Production		—			3,708			3,435								7,143
General and administrative		1,596			—			1,193								2,789
Interest		71			—			137			2,425			2(a,e,f,g)		2,633
Maintenance of patents		243			—			—								243
Depletion, depreciation and asset write-downs		7,216			—			6,916			15,510			2(c)		29,642
Site restoration		—			—			249								249

		9,126			3,708			11,930			17,935					42,699

Earnings (loss) before the following:		(8,987	)		14,599			3,645			(17,935	)				(8,678	)
Gain on sale and distribution of Oncolytics shares		13,224			—			—								13,224
Share of loss from equity investment in Oncolytics		(471	)		—			—								(471	)

Earnings (loss) before income taxes		3,766			14,599			3,645			(17,935	)				4,075
Income tax expense (recovery)		—			—			1,822			(1,510	)		3		312

Net earnings (loss)		3,766			14,599			1,823			(16,425	)				3,763

Earnings per share *[note 4]*																0.09

See accompanying notes to unaudited pro forma consolidated financial statements

F-6

Hawker Resources Inc.

NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
As at September 30, 2003 and for the Nine Months Ended September 30, 2003 and Year Ended
December 31, 2002
(Unaudited)
(thousands of Cdn. dollars, except share and per share amounts)

1. BASIS OF PRESENTATION

These unaudited pro forma consolidated financial statements have been prepared by management in accordance with Canadian generally accepted accounting principles for inclusion in the short form prospectus of Hawker Resources Inc. (“Hawker”) dated December 19, 2003 relating to the sale and issue of 11,200,000 common shares and in the opinion of management contain all adjustments necessary for fair presentation. These unaudited pro forma financial statements are based on the historical financial statements of Hawker and Pointwest Energy Inc. (“Pointwest”) and historical statements of revenues and operating expenses of the W4M properties acquired from Southward Energy Ltd. (“Southward”), together with other information available to Hawker management.

The unaudited pro forma financial statements have been prepared to give effect to the following transactions:

(a) the operating revenues and expenses for the period January 1, 2003 to June 30, 2003 and for the year ended December 31, 2002 of the 50% interest in certain oil and gas properties west of the fourth meridian (“W4M Properties”) acquired by Hawker on June 30, 2003 from Southward;

(b) the proposed acquisition of Pointwest accounted for under the purchase method of accounting for cash consideration of $74,473;

(c) the sale and issue of flow-through common shares on December 5, 2003; and

(d) the sale and issue of 11,200,000 common shares and application of the net proceeds thereof, and borrowings of $31,801 under bank loans in connection with the proposed acquisition of Pointwest.

These pro forma financial statements are not necessarily indicative of the results that actually would have occurred if the transactions reflected herein had been in effect on the dates indicated or of the results which may be obtained in the future.

The unaudited pro forma consolidated financial statements should be read in conjunction with:

(a) the December 31, 2002 audited financial statements of Hawker;

(b) the December 31, 2002 audited financial statements of Pointwest;

(c) the unaudited consolidated financial statements of Hawker as at and for the nine months ended September 30, 2003;

(d) the unaudited consolidated financial statements of Pointwest as at and for the nine months ended September 30, 2003;

(e) the audited statement of revenues and operating expenses of the W4M properties acquired from Southward for the year ended December 31, 2002; and

(f) the unaudited statement of revenues and operating expenses of the W4M properties acquired from Southward for the six month period ended June 30, 2003.

F-7

Hawker Resources Inc.

NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
As at September 30, 2003 and for the Nine Months Ended September 30, 2003 and Year Ended
December 31, 2002
(Unaudited)
(thousands of Cdn. dollars, except share and per share amounts)

2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS

The pro forma balance sheet gives effect to the transactions as if they occurred on September 30, 2003 and the pro forma statements of earnings give effect to the transactions as if they occurred on January 1, 2002. The revenues and operating expenses of the W4M properties for the period from the date of acquisition on June 30, 2003 to September 30, 2003 are included in the unaudited interim consolidated statement of earnings and deficit for the nine months ended September 30, 2003 of Hawker. Accordingly, the pro forma adjustments with respect to the W4M properties in the nine month pro forma consolidated statement of earnings are only for the six month period from January 1, 2003 to June 30, 2003.

The accounting policies used in the preparation of the pro forma financial statements are in accordance with those disclosed in Hawker’s audited financial statements for the year ended December 31, 2002 and unaudited financial statements for the nine months ended September 30, 2003.

These pro forma consolidated financial statements give effect to the following transactions, assumptions and adjustments:

Acquisition of 50% interest in W4M properties

(a) interest at 5.25% on $24,600 in bank loans obtained to finance the acquisition amounting to $417 for the six months ended June 30, 2003 and $1,294 for the year ended December 31, 2002;

Acquisition of Pointwest

(b) The acquisition of Pointwest using the purchase method of accounting and a preliminary allocation (which may be subject to additional adjustments) of the purchase price to the fair value of the assets and liabilities acquired for purposes of preparing these unaudited pro forma financial statements is as follows:


	$
Cash		220
Accounts receivable		5,267
Prepaids		317
Oil and gas properties		87,292

Total assets		93,096
Accounts payable and accrued liabilities		(12,599	)
Bank loan		(5,250	)
Future site restoration and abandonment		(774	)

Net cash cost		74,473

F-8

Hawker Resources Inc.

NOTES TO PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
As at September 30, 2003 and for the Nine Months Ended September 30, 2003 and Year Ended
December 31, 2002
(Unaudited)
(thousands of Cdn. dollars, except share and per share amounts)

The adjustments to the Pointwest financial statements to reflect the above purchase allocation are as follows:


	$
Capital assets		30,800
Elimination of share capital		24,901
Elimination of retained earnings		8,043
Future income taxes		10,729

Net cash cost		74,473

(c) the provision for depletion and depreciation reflects an increase of $10,297 resulting from the oil and gas properties acquired in 2(a) and 2(b) for the nine month period ending September 30, 2003 and $15,510 for the year ended December 31, 2002;

Sale and issue of shares and application of net proceeds, and bank borrowings

(d) the net proceeds of this offering of 11,200,000 common shares by Hawker amounting to $42,452;

(e) the proceeds of a bank loan for $21,801 with interest at 5.25% amounting to $856 for the nine month period ending September 30, 2003 and $1,193 for the year ended December 31, 2002;

(f) the proceeds of a bridge bank loan facility for $10,000 with interest at 7.00% amounting to $524 for the nine month period ending September 30, 2003 and $700 for the year ended December 31, 2002; and

Sale and issue of flow-through common shares

(g) the net proceeds of a private placement of 2,900,000 common shares on a flow-through basis of $14,514 reflected as a repayment on the bank loans in (e) and (f) above and the related interest expense reduction of $570 for the nine month period ending September 30, 2003 and $762 for the year ended December 31, 2002.

3. INCOME TAXES

At September 30, 2003, Hawker had large non-capital losses and unclaimed expenditures for income tax purposes, the benefit of which has not been recorded in the financial statements. These unrecorded future income tax assets exceeded the total future tax liabilities arising from pro forma adjustments, including differences between the financial reporting and tax bases of assets recorded in the Pointwest acquisition. Accordingly, it has been assumed that the benefit of these future tax assets would be recorded to offset any future income tax liabilities. The income tax expense recorded in the pro forma consolidated statements of earnings reflects the large corporations tax that would be incurred based on the unaudited pro forma consolidated financial statements.

4. EARNINGS PER SHARE

The pro forma earnings per share is based on the number of Hawker shares outstanding at September 30, 2003 (21,897,200 common shares and 3,874,437 class A shares) adjusted to account for the issue of 11,200,000 common shares under this offering in (d) and the issue of 2,900,000 common shares in (g) above as if these shares had been issued January 1, 2002.

F-9

Report of Independent Registered
Public Accounting Firm

To the Board of Directors of
Hawker Resources Inc.

We have audited the consolidated balance sheets of Pointwest Energy Inc. as at December 31, 2002 and 2001 and the consolidated statements of operations and retained earnings (deficit) and cash flows for each of the years in the two-year period ended December 31, 2002 and for the period from July 25, 2000 to December 31, 2000. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2002 and 2001 and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2002 and for the period from July 25, 2000 to December 31, 2000 in accordance with Canadian generally accepted accounting principles.

Canadian generally accepted accounting principles vary in certain 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 12 to the financial statements

(signed) KPMG LLP
Chartered Accountants

Calgary, Canada
April 12, 2003, except for note 11 as to which the date is December 12, 2003

F-10

Pointwest Energy Inc.
Consolidated Balance Sheets


	September 30,		December 31,		December 31,
	2003		2002		2001
	(unaudited)
Assets
Current
Cash and cash equivalents (note 4)	$	219,815	$	243,223	$	8,731,454
Accounts receivable		5,267,443		5,353,302		935,728
Prepaid expenses and deposits		316,776		177,969		144,536

		5,804,034		5,774,494		9,811,718
Property and equipment (note 5)		56,492,081		42,618,103		13,536,024

	$	62,296,115	$	48,392,597	$	23,347,742

Liabilities
Current
Accounts payable and accrued liabilities	$	12,599,416	$	12,581,545	$	2,891,134
Demand credit facility (note 6)		5,250,000		5,150,000		—

		17,849,416		17,731,545		2,891,134
Provision for site restoration and abandonment		774,183		370,283		121,683
Future income taxes (note 8)		10,728,577		5,228,577		3,445,181

		29,352,176		23,330,405		6,457,998

Shareholders’ Equity
Share capital (note 7)		24,900,551		24,900,551		18,551,551
Retained earnings (deficit)		8,043,388		161,641		(1,661,807	)

		32,943,939		25,062,192		16,889,744

	$	62,296,115	$	48,392,597	$	23,347,742

Subsequent event (note 11)

On behalf of the Board

(signed) David A. Tuer Director (signed) Ronald P. Mathison Director

See accompanying notes

F-11

Pointwest Energy Inc.
Consolidated Statements of Operations and Retained Earnings (Deficit)


	Nine months ended												Period from July 25
	September 30						Years ended December 31						to December 31
	2003			2002			2002			2001			2000
	(unaudited)			(unaudited)
Revenue
Petroleum and natural gas sales	$	40,069,997		$	8,555,195		$	20,248,861		$	1,120,382		$	—
Royalties, net of ARTC		(9,707,815	)		(1,806,422	)		(4,701,366	)		(149,667	)		—

		30,362,182			6,748,773			15,547,495			970,715			—
Interest and other income		—			27,731			27,731			288,049			14,723

		30,362,182			6,776,504			15,575,226			1,258,764			14,723

Expenses
Production		4,091,978			1,945,965			3,435,315			483,000			—
General and administrative		770,593			689,378			1,193,065			799,734			211,586
Interest		212,893			57,288			137,025			55,538			—
Depletion, depreciation and site restoration		11,878,593			3,448,228			7,164,503			2,510,692			4,251

		16,954,057			6,140,859			11,929,908			3,848,964			215,837

Income (loss) before taxes		13,408,125			635,645			3,645,318			(2,590,200	)		(201,114	)

Capital taxes		26,378			19,000			38,474			25,000			—
Future income tax (recovery) (note 8)		5,500,000			550,000			1,783,396			(1,154,507	)		—

		5,526,378			569,000			1,821,870			(1,129,507	)		(201,114	)

Income (loss) for the period		7,881,747			66,645			1,823,448			(1,460,693	)		(201,114	)
Retained earnings (deficit), beginning of period		161,641			(1,661,807	)		(1,661,807	)		(201,114	)		—

Retained earnings (deficit), end of period	$	8,043,388		$	(1,595,162	)	$	161,641		$	(1,661,807	)	$	(201,114	)

See accompanying notes

F-12

Pointwest Energy Inc.
Consolidated Statements of Cash Flows


													Period from
	Nine months ended												July 25 to
	September 30						Years ended December 31						December 31
	2003			2002			2002			2001			2000
	(unaudited)			(unaudited)
Operating
Income (loss) for the period	$	7,881,748		$	66,645		$	1,823,448		$	(1,460,693	)	$	(201,114	)
Depletion, depreciation and site restoration		11,878,593			3,448,228			7,164,503			2,510,692			4,251
Future income tax provision (recovery)		5,500,000			550,000			1,783,396			(1,154,507	)		—

		25,260,341			4,064,873			10,771,347			(104,508	)		(196,863	)
Changes in non-cash working capital (note 10)		(1,752,754	)		(2,184,946	)		(2,704,009	)		(418,780	)		14,879

		23,507,587			1,879,927			8,067,338			(523,288	)		(181,984	)

Financing
Issue of common shares		—			6,349,000			6,349,000			15,103,000			4,935,100
Bank borrowing		100,000			5,800,000			5,150,000			—			—

		100,000			12,149,000			11,499,000			15,103,000			4,935,100

Investing
Expenditures on property and equipment		(24,650,432	)		(19,614,267	)		(29,575,214	)		(7,880,792	)		(70,188	)
Acquisition of property and equipment		(698,240	)		(6,422,768	)		(6,422,768	)		—			—
Purchase of Myriad Energy Corporation (note 3)		—			—			—			(4,822,537	)		—
Changes in non-cash working capital (note 10)		1,717,677			4,019,790			7,943,413			2,172,143			—

		(23,630,995	)		(22,017,245	)		(28,054,569	)		(10,531,186	)		(70,188	)

(Decrease) increase in cash and cash equivalents		(23,408	)		(7,988,318	)		(8,488,231	)		4,048,526			4,682,928
Cash and cash equivalents, beginning of period		243,223			8,731,454			8,731,454			4,682,928			—

Cash and cash equivalents, end of period	$	219,815		$	743,136		$	243,223		$	8,731,454		$	4,682,928

See accompanying notes

F-13

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

1. Nature of operations

Pointwest Energy Inc. (the “Company”) is engaged in the exploration for and production of petroleum and natural gas predominately in Western Canada. The Company was incorporated under the Business Corporations Act (Alberta) on July 25, 2000. In December 2000, the articles of incorporation were amended to remove the private company restrictions.

2. Summary of significant accounting policies

These consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include the accounts of the Company and its wholly owned subsidiary, Myriad Energy Corporation and a production partnership, Pointwest Energy. In all material respects, the accounting principles followed are generally accepted in the United States except as disclosed in note 12. The financial statements have, in management’s opinion, been properly prepared using careful judgment within reasonable limits of materiality and within the framework of the significant accounting policies summarized below:

a) Property and equipment

i) Capitalized costs

The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under this method, all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Costs include lease acquisitions, lease rentals on non-producing properties, geological and geophysical costs, and costs of drilling both productive and non-productive wells and production equipment costs. General and administrative costs are not capitalized other than to the extent of the Company’s working interest in operated capital expenditure programs on which operator’s fees have been charged equivalent to standard industry operating agreements. Proceeds from the sale of properties are applied against capitalized costs and gains or losses are not recognized unless such sale would alter the depletion rate by more than 20%.

ii) Depletion and depreciation

Depletion and depreciation of oil and gas properties, net of estimated salvage or residual value, is provided using the unit-of-production method based upon estimated gross proven petroleum and natural gas reserves as determined by independent engineers. For depletion and depreciation purposes, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.

Office equipment is depreciated on a declining balance basis over its estimated useful life at rates varying from 20% to 50%.

iii) Impairment test

The Company calculates a ceiling test whereby the carrying value of its property and equipment, net of recorded future income taxes and the accumulated provision for future site restoration and abandonment costs, is compared each reporting period-end to an estimate of future net cash flow from the production of gross proven reserves plus the lower of cost or market of unevaluated land and seismic. Net cash flow is estimated using period-end prices, less estimated future general and administrative expenses, financing costs, estimated future site restoration and abandonment costs and income taxes. Should this comparison indicate an excess carrying value, the excess is charged against operations in the period as additional depletion and depreciation.

b) Site restoration and abandonment costs

The estimated cost of site restoration and abandonments is based on the current cost and the anticipated method and extent of site restoration in accordance with existing legislation and industry practice. Estimated future site restoration and abandonment costs are accrued on the unit-of-production basis based on gross proven reserves. The provision is recorded on the statement of operations. Future site restoration and abandonment expenditures are charged to the accumulated provision as incurred.

F-14

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

c) Use of estimates

The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The amounts recorded for depletion and depreciation of property and equipment and the provision for site restoration and abandonment and the ceiling test are based on estimates of gross proven reserves, production rates, oil and gas prices, future costs and other relevant assumptions. These estimates are reviewed regularly and changes in such estimates in future years could be significant. As adjustments become necessary, they are reported in earnings in the periods in which they become known.

d) Joint operations

Substantially all of the exploration and production activities of the Company are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.

e) Flow-through shares

The Company finances a portion of its exploration and development activities through the issue of flow-through shares. Under the terms of the flow-through share issues, the tax deduction of the related expenditures are renounced to subscribers. For accounting purposes, a future tax liability is recognized and share capital is reduced when the shares are issued.

f) Future income taxes

The Company follows the liability method of accounting for income taxes. Under this method future tax assets and liabilities are determined based on differences between financial reporting and income tax bases of assets and liabilities, and are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change is substantively enacted.

g) Stock-based compensation plan

The Company has a stock based compensation plan, which is described in note 7. No compensation expense is recorded for this plan when stock options are issued to employees and directors. Any consideration paid on the exercise of stock options is credited to share capital.

h) Revenue recognition

Revenues from the sale of petroleum and natural gas are recorded when title passes to an external party.

3. Acquisition

In May 2001, the Company acquired all of the issued and outstanding shares of Myriad Energy Corporation (a private oil and gas company) for total cash consideration of $5,149,413, including $148,619 of acquisition costs. The transaction has been accounted for using the purchase method with the results of operations of Myriad included in the accounts from May 2001.


Cash	$	326,876
Non-cash working capital		(42,628	)
Property and equipment		8,061,487
Future site restoration and abandonment		(83,183	)
Future tax liability		(3,113,139	)

		5,149,413
Less: cash acquired		(326,876	)

Cash expenditure	$	4,822,537

F-15

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

4. Cash and cash equivalents


	September 30,		December 31,		December 31,
	2003		2002		2001
Cash in bank	$	219,815	$	243,223	$	3,734,654
Term deposits		—		—		4,996,800

	$	219,815	$	243,223	$	8,731,454

5. Property and equipment

September 30, 2003

Accumulated

depletion and

Cost

depreciation

Net

Petroleum and natural gas properties

77,255,770

20,809,401

56,446,369

Office equipment

103,351

57,639

45,712

77,359,121

20,867,040

56,492,081


	December 31, 2002
			Accumulated
			depletion and
	Cost		depreciation		Net
Petroleum and natural gas properties	$	51,914,893	$	9,346,400	$	42,568,493
Office equipment		95,556		45,946		49,610

	$	52,010,449	$	9,392,346	$	42,618,103


	December 31, 2001
			Accumulated
			depletion and
	Cost		depreciation		Net
Petroleum and natural gas properties	$	15,924,543	$	2,450,400	$	13,474,143
Office equipment		87,924		26,043		61,881

	$	16,012,467	$	2,476,443	$	13,536,024

At September 30, 2003 petroleum and natural gas properties included undeveloped land of $1,549,363 (December 31, 2002 — $1,332,401; December 31, 2001 — $891,826; December 31, 2000 — $Nil), which has been excluded from the depletion calculation. Future capital expenditures in the amount of $2,603,000 (December 31, 2002 — $2,942,000; December 31, 2001 — $1,028,000; December 31, 2000 — $Nil ) have been included in the depletion calculation.

At December 31, 2001, the application of the ceiling test resulted in a $1.7 million pre-tax write-down ($960,000 after tax) of the oil and gas assets.

At September 30, 2003 total future site restoration and abandonment costs are estimated to be $2,046,200 (December 31, 2002 — $1,657,000) of which $774,183 has been accrued as at September 30, 2003 (December 31, 2002 — $370,283).

The Company did not capitalize any general and administrative costs during any of the periods,other than to the extent of the Company’s working interest in operated capital expenditure programs on which operator’s fees have been charged equivalent to standard industry operating agreements.

F-16

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

6. Demand credit facility

The Company has a $20.2 million demand revolving credit facility at an interest rate of prime plus 0.5% when the debt to equity ratio is equal to or less than 1.5 to 1 and prime plus 0.75% when the debt to equity ratio is greater than 1.5 to 1. Security is provided by a general security agreement, and a $25.0 million floating debenture. The Company had borrowed $5,250,000 under this facility as at September 30, 2003 (December 31, 2002 — $5,150,000).

7. Share capital

a) Authorized

Unlimited number of Class A voting shares

b) Issued


	Number
Class A common shares	of Shares		Amount
Balance — December 31, 2000		1,249,100	$	5,353,100
Private placements		2,499,600		12,498,000
Flow-through shares		279,000		1,395,000
Tax benefits related to renounced expenditures on flow-through shares		—		(594,549	)
Share subscription receivable		—		(100,000	)

Balance — December 31, 2001		4,027,700		18,551,551
Share subscription received		—		100,000
Private placements		1,249,800		6,249,000

Balance — September 30, 2003 and December 31, 2002		5,277,500	$	24,900,551

c) Private placement

Under the terms of a private placement in December 2000, participants subscribed for units of the Company. Subscriptions for less than 50,000 units received one common share per unit. Participants subscribing for 50,000 units or greater received 0.1 common shares, 0.6 Class A Call Obligation and 0.3 Class B Obligation. Each Class A and Class B Obligation required the holder to subscribe for 1 common share at a price of $5.00 on or before June 30, 2002. During 2001, obligations called and paid resulted in the issue of 2,499,600 class A common shares for proceeds of $12,498,000. During 2002, the balance of obligations were called and paid resulting in the issue of 1,249,800 class A common shares for proceeds of $6,249,000.

d) Flow-through shares

In December 2001, 279,000 flow-through Class A shares were issued at $5.00 per share for gross proceeds of $1,395,000. At December 31, 2001 the tax deductions related to these proceeds were renounced to the investors and the Company had met its obligations of these expenditures. Of the 279,000 flow through shares issued during 2001, 264,000 were issued to directors.

e) Stock options

The Company has a stock option plan, administered by the board of directors, in which up to 791,610 shares are reserved for issuance. Under the plan, the options that have been granted vest one-third per year and expire five years from date of issuance.

F-17

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

7. Share capital (continued)

Shares have been reserved for the following stock options outstanding:

Period ended

Year ended

September 30, 2003

December 31, 2002

December 31, 2001

Weighted

Average

Exercise Price

Shares

Opening

778,417

5.00

573,933

5.00

187,180

5.00

Granted

13,194

7.45

204,484

5.00

386,753

5.00

Closing

791,611

5.04

778,417

5.00

573,933

5.00

The following summarizes information about stock options outstanding as at September 30, 2003:


	Number		Weighted Average		Number
Exercise	Outstanding		Remaining		Exercisable		Weighted Average
Price	At September 30,		Contractual Life		At September 30,		Exercise Price
$	2003		(years)		2003		$
5.00		778,417		2.0		518,945		5.00
7.45		13,194		3.5		—		—

		791,611		2.0		518,945		5.00

During the period ended September 30, 2003, the Company granted 13,194 options to an employee. For the purposes of pro forma disclosure, the estimated fair value of the options is recognized over the vesting period of the option. Had the fair value method been used, the Company’s income for the nine months ended September 30, 2003 would have been reduced by $8,816.

The value of the stock options granted was determined using the Black-Scholes option pricing model and resulted in a total pro forma cost of $21,800 based on the following assumptions: risk free interest rate of 5.0%; expected term of 5.0 years; weighted average stock volatility of 0%; and no expected future dividends.

8. Income taxes

The components of the future income tax liability are:


	September 30,			December 31,			December 31,
	2003			2002			2001
Property and equipment	$	11,344,630		$	5,577,963		$	3,579,250
Provision for future site restoration		(306,731	)		(155,963	)		(51,861	)
Benefit of non-capital loss		—			—			(94,517	)
Benefit of provincial tax deduction		(309,342	)		(193,423	)		—
Other		—			—			12,309

Liability per financial statements	$	10,728,577		$	5,228,577		$	3,445,181

F-18

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

8. Income taxes (continued)

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


	September 30						December 31
	2003			2002			2002			2001			2000
Expected income tax rate		40.62	%		42.12	%		42.12	%		42.62	%		44.62	%

Expected income tax expense (recovery)	$	5,446,380		$	267,734		$	1,535,408		$	(1,103,943	)	$	(89,696	)
Crown royalties and production taxes		3,561,405			735,792			1,996,773			56,280			—
ARTC		(124,829	)		—			(193,206	)		(14,069	)		—
Resource allowance		(3,075,362	)		(459,022	)		(1,343,903	)		33,751			24,009
Benefit of provincial tax deduction		(115,919	)		—			(193,423	)		—			—
Effect of federal and provincial tax rate reduction		(316,526	)		—			(41,382	)		(37,043	)		—
Other		124,851			5,496			23,129			(24,412	)		227
Recorded benefit of losses		—			—			—			(65,071	)		65,460

Income tax expense (recovery)	$	5,500,000		$	550,000		$	1,783,396		$	(1,154,507	)	$	—

9. Financial instruments

a) Fair values of financial assets and liabilities

Financial instruments consist of cash and cash equivalents, accounts receivable, deposits, accounts payable and accrued liabilities and the demand credit facility. At September 30, 2003 and December 31, 2002 and 2001 there are no significant differences between the carrying amounts reported on the balance sheet and estimated fair values. At September 2003 and December 31, 2002 and 2001, the Company had no outstanding hedging contracts.

b) Credit risk

The majority of the accounts receivable are in respect of oil and natural gas operations. The Company generally extends unsecured credit to these customers, and therefore, the collection of accounts receivables may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit loss in the collection of receivables to date.

c) Interest rate risk

The Company is exposed to a floating rate of interest on its bank borrowings.

F-19

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

10. Supplemental cash flow information

a) Change in non-cash working capital


	September 30						December 31
	2003			2002			2002			2001			2000
Accounts receivable	$	85,859		$	(2,819,724	)	$	(4,417,574	)	$	(932,787	)	$	(2,941	)
Prepaid expenses and deposits		(138,807	)		59,408			(33,433	)		(89,585	)		72,771
Accounts payable and accrued liabilities		17,871			4,595,160			9,690,411			2,818,363			(54,951	)
Working capital acquired from Myriad (note 3)		—			—			—			(42,628	)		—

	$	(35,077	)	$	1,834,844		$	5,239,404		$	1,753,363		$	14,879

The change in non-cash working capital has been allocated to the following activities:


	September 30						December 31
	2003			2002			2002			2001			2000
Operating	$	(1,752,754	)	$	(2,184,946	)	$	(2,704,009	)	$	(418,780	)	$	14,879
Investing	$	1,717,677		$	4,019,790		$	7,943,413		$	2,172,143		$	—

b) Interest and capital tax paid


	September 30				December 31
	2003		2002		2002		2001		2000
Interest	$	212,893	$	57,288	$	192,563	$	—	$	—
Capital tax	$	26,378	$	19,000	$	63,474	$	—	$	—

11. Subsequent event

The Company has signed a lock-up agreement with a public company Hawker Resources Inc. for the sale of all of its shares at a price of $12.71 per share. As part of the sale, the Company has agreed to pay the holders of 791,611 outstanding stock options approximately $6.1 million in exchange for cancellation of their options.

F-20

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

12. Reconciliation of Canadian and United States generally accepted accounting principles

The financial statements are prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) which, in most respects, conform to United States generally accepted accounting principles (“US GAAP”). Significant differences between Canadian GAAP and US GAAP are as follows:


			September 30,			December 31,			December 31,			December 31,
	Notes		2003			2002			2001			2000
Net earnings (loss) — Canadian GAAP			$	7,881,747		$	1,823,448		$	(1,460,693	)	$	(201,114	)
Production expense		(b)		(32,250	)		—			—			—
Related income taxes				13,100			—			—			—
Depletion, depreciation and site restoration		(b)(c)		764,062			495,853			(3,000,000	)		—
Related income taxes				(310,362	)		(208,853	)		1,278,600			—
Cost of renunciation of tax benefits on expenditures		(d)		—			—			(594,549	)		—

Net earnings (loss) before cumulative change in accounting policy — US GAAP			$	8,316,297		$	2,110,448		$	(3,776,642	)	$	(201,114	)
Cumulative effect of change in accounting policy, net of related income taxes		(b)		144,458			—			—			—

Net earnings (loss) and comprehensive earnings (loss) — US GAAP			$	8,460,755		$	2,110,448		$	(3,776,642	)	$	(201,114	)

Balance sheet items in accordance with US GAAP are as follows:


			September 30, 2003				December 31, 2002					December 31, 2001
			Canadian		US		Canadian		US			Canadian			US
	Notes		GAAP		GAAP		GAAP		GAAP			GAAP			GAAP
Property and equipment		(b)(c)	$	56,492,081	$	54,703,269	$	42,618,103	$	40,113,956		$	13,536,024		$	10,536,024
Provision for site restoration and abandonment		(b)		774,183		507,250		370,283		370,283			121,683			121,683
Future income taxes		(b)(c)		10,728,577		10,062,090		5,228,577		4,158,830			3,445,181			2,166,581
Share capital		(d)		24,900,551		25,495,100		24,900,551		25,495,100			18,551,551			19,146,100
Retained earnings (deficit)		(b)(c)(d)		8,043,388		6,593,447		161,641		(1,867,308	)		(1,661,807	)		(3,977,756	)

(a) Stock based compensation

For US reporting purposes, the statement of Financial Accounting Standard No. 123 “Accounting for Stock Based Compensation” (“SFAS 123”) requires the reporting of pro forma amounts for compensation expense that would have been recorded for the issuance of share options using a fair value option pricing model. On January 1, 2003, the Company adopted the new CICA standard for stock-based compensation, resulting in the pro forma disclosure contained in note 7. The Company has applied this change prospectively commencing on the date of adoption, effectively eliminating the US GAAP difference associated with this accounting.

The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions:


	2002			2001
Risk free interest rate		5.00	%		5.00	%
Dividend yield		0	%		0	%
Volatility factors of expected market price		0	%		0	%
Weighted average expected life of the options	5 years			5 years

F-21

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

Pro forma disclosures of earnings (loss) are presented below as if the Company had adopted the cost recognition requirements under SFAS 123. For the purposes of pro forma disclosure, the estimated fair value of the options is recognized over the vesting period of the option. The compensation cost for the stock-based compensation was approximately $368,642 in 2002 and $223,472 in 2001.


		2002		2001
Earnings (loss) — US GAAP	As reported	$	1,823,448	$	(1,460,693	)
	Pro forma		1,454,806		(1,684,165	)

(b) Asset retirement obligations

For US GAAP purposes, the Company has adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”. Under US GAAP, legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or the normal operation of long-lived assets must be recognized at fair value in the period in which the liability is incurred. The fair value is added to the carrying amount of the associated asset. The liability is accreted at the end of each period through charges to operating expenses.

For the period ended September 30, 2003, the change results in a reduction to depletion, depreciation and site restoration expense of $344,374 (net of tax - $204,489) and an additional charge to production expense of $32,250 (net of tax - $19,150). The cumulative effect on the consolidated balance sheet is an increase in property and equipment of $295,647 and a decrease of $266,933 to the provision for future site restoration and abandonment costs.

US GAAP requires that the cumulative impact of this accounting change be presented in the period of the change and prior periods are not restated. The reported expenses would have been reduced by $149,271 (net of tax — $86,398) and $101,185 (net of tax — $58,060) at December 31, 2002 and 2001, respectively had the change been applied retroactively with restatement.

(c) Impairments

Under both US and Canadian GAAP, property, plant and equipment must be assessed for potential impairments. Under US GAAP, if the sum of the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs), discounted at ten percent, is less than the net capitalized costs (net of deferred income taxes), the excess is charged to expense. As disclosed in note 2, under Canadian GAAP, the impairment loss is the difference between the net carrying value of the asset and the estimated value of future net revenues. For the nine months ended September 30, 2003, a reduction in depletion expense of $419,688 (net of tax - $249,211) would be recorded due to impairment charges recorded in fiscal 2001 under US GAAP. For the year ended December 31, 2002, a reduction in depletion expense of $495,853 (net of tax - $287,000) would be recorded due to impairment charges recorded in fiscal 2001 under US GAAP. For the year ended December 31, 2001, an additional impairment charge of $3,000,000 (net of tax - $1,721,400) would have been recorded under US GAAP. The resulting differences in recorded carrying values of impaired assets will result in further differences in depreciation and depletion expense in subsequent years.

(d) Flow-through shares

The Company financed 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 the 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.

F-22

REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM

To the Directors of
Hawker Resources Inc.

We have audited the balance sheets of Hawker Resources Inc. as at December 31, 2003 and 2002 and the statements of earnings (loss) and deficit and cash flows for each of the years in the three year period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in Canada and 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, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003 in accordance with Canadian generally accepted accounting principles.

As discussed in note 3 to the financial statements, in 2003 the Company adopted new accounting recommendations with respect to stock based compensation.


Calgary, Canada
March 10, 2004 (except for note 17 which is		(signed) Ernst & Young LLP
as of March 17, 2004)		Chartered Accountants

F-23

Hawker Resources Inc.

Balance Sheets
As at December 31


(in thousands of Canadian dollars)	2003			2002
ASSETS
Current
Cash	$	—		$	289
Accounts receivable		11,577			27
Investments		2,500			—
Prepaids and other current assets		1,845			176

		15,922			492
Assets held for sale (Note 5)		2,190			3,500
Capital assets (Notes 4, 6 and 7)		166,990			23

	$	185,102		$	4,015

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current
Accounts payable and accrued liabilities	$	23,750		$	80
Bank loan (Note 7)		10,000			—

		33,750			80
Bank loan (Note 7)		44,149			—
Leasehold inducements		247			—
Alberta Heritage Foundation grant (Note 8)		—			387
Asset retirement obligations (Note 3)		3,499			—
Commitments and contingencies (Notes 4, 15 and 16)
Shareholders’ Equity (Note 9)
Share capital		110,204			12,741
Contributed Surplus		132			—
Deficit		(6,879	)		(9,193	)

		103,457			3,548

	$	185,102		$	4,015

See accompanying notes to the financial statements


On behalf of the Board:

(signed) David A. Tuer		(signed) Ronald P. Mathison
Director		Director

F-24

Hawker Resources Inc.

Statements of Earnings (Loss) and Deficit
For the years ended December 31


(in thousands of Canadian dollars, except per share amounts)	2003			2002			2001
	Restated
	(Note 4 (d))
Revenue
Production revenue	$	17,582		$	—		$	—
Royalties		(4,205	)		—			—

		13,377			—			—
Interest income		78			32			515
Other		487			107			214

		13,942			139			729

Expenses
Production		2,028			—			—
General and administrative (Note 10)		4,590			1,621			7,106
Research and development		—			—			9,255
Interest on long-term debt		679			71			787
Depletion, depreciation and asset write-downs		8,933			26			9,655

		16,230			1,718			26,803

Loss before the following		(2,288	)		(1,579	)		(26,074	)
Lease abandonment expense		(502	)		—			—
Operating costs and write-downs associated with assets held for sale		(190	)		(7,408	)		—
Gain on the sale and distribution of Oncolytics shares (Note 4)		—			13,067			3,004
Gain on dilution of investment in Oncolytics (Note 4)		—			—			357
Share of loss from equity investment in Oncolytics (Note 4)		—			(314	)		(1,831	)
Alberta Heritage Foundation grant settlement (Note 8)		368			—			—

Earnings (loss) before taxes		(2,612	)		3,766			(24,544	)

Taxes
Future income tax recovery (Note 11)		(5,271	)		—			(1,556	)
Capital taxes		345			—			—

		(4,926	)		—			(1,556	)

Net earnings (loss)		2,314			3,766			(22,988	)
Deficit, beginning of year		(9,193	)		(72,855	)		(49,867	)
Reduction of stated capital (Note 9)		—			59,896			—

Deficit, end of year	$	(6,879	)	$	(9,193	)	$	(72,855	)

Basic and diluted net earnings per common share (Note 9)	$	0.14		$	0.76		$	(4.64	)

See accompanying notes to the financial statements

F-25

Hawker Resources Inc.

Statements of Cash Flows
Years ended December 31


(in thousands of Canadian dollars)	2003			2002			2001
	Restated
	(Note 4 (d))
OPERATING ACTIVITIES
Net earnings (loss)	$	2,314		$	3,766		$	(22,988	)
Add (deduct) non-cash items:
Depletion, depreciation and asset write-downs		9,078			7,216			9,655
Accretion expense		100			—			—
Alberta Heritage Foundation grant settlement (Note 8)		(368	)		—			—
Future income tax recovery		(5,271	)		—			(1,556	)
Stock-based compensation (Note 10)		132			—			—
Share of loss from equity investment in Oncolytics		—			314			1,831
Gain on sale and distribution of Oncolytics shares		—			(13,067	)		(3,004	)
Gain on dilution of investment in Oncolytics		—			—			(357	)
Issuance of stock options for services		—			12			—

		5,985			(1,759	)		(16,419	)
Net change in non-cash working capital (Note 14)		5,660			(4,779	)		3,642

		11,645			(6,538	)		(12,777	)

INVESTING ACTIVITIES
Proceeds from sale of capital assets		1,173			44			—
Acquisition of oil and gas properties (Note 4)		(139,784	)		—			—
Additions to oil and gas properties		(14,504	)		—			—
Additions to other capital assets		(279	)		—			(944	)
Leasehold inducements received		247			—			—
Proceeds from sale of Oncolytics shares		—			6,898			3,481
Net change in non-cash working capital (Note 14)		806			—			—

		(152,341	)		6,942			2,537

FINANCING ACTIVITIES
Common shares issued on exercise of options		192			—			126
Common shares issued for cash		105,633			—			—
Issue of debentures and warrants		3,645			—			—
Increase in bank loan		37,720			—			—
Share issue costs		(6,736	)		—			—
Costs of distribution of shares in Oncolytics		—			(46	)		—
Repayment of bank debt		—			(5,910	)		(2,866	)
Alberta Heritage Foundation royalty payment (Note 8)		(19	)		—			—
Net change in non-cash working capital (Note 14)		(28	)		—			—

		140,407			(5,956	)		(2,740	)

Decrease in cash		(289	)		(5,552	)		(12,980	)
Cash, beginning of year		289			5,841			18,821

Cash, end of year	$	—		$	289		$	5,841

Supplemental disclosure of cash flow information (Note 14)

See accompanying notes to the financial statements

F-26

Hawker Resources Inc.

Notes to Financial Statements
Years ended December 31, 2003, 2002 and 2001
(Tabular amounts in thousands of Canadian dollars, unless otherwise noted)

1.   NATURE OF OPERATIONS

Prior to 2002, SYNSORB Biotech Inc. (“SYNSORB”) conducted pharmaceutical drug research and development. On December 10, 2001 SYNSORB terminated its drug development activities. At the Annual and Special Meeting of SYNSORB shareholders held April 3, 2003, shareholders approved the planned conversion of the company into an oil and gas enterprise and changed the company’s name to Hawker Resources Inc.

2.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The financial statements of Hawker Resources Inc. (the “Company” or “Hawker”) have been prepared in accordance with Canadian generally accepted accounting principles. These are different in some respects from those generally accepted in the United States. The significant differences are described in note 18 “Reconciliation of Canadian and United States Generally Accepted Accounting Principles”. The timely preparation of financial statements requires that management makes estimates and assumptions, and use judgement regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

(a)   Capital Assets

Cost

The Company follows the full cost method of accounting whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized in a single Canadian cost center. Such costs include lease acquisition, lease rentals on undeveloped properties, geological and geophysical, drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.

Gains or losses are not recognized upon the disposition of oil and gas properties unless such a disposition would change the depletion rate by 20 percent or more. Gains and losses are recognized upon the disposition of other assets.

Other capital assets are recorded at cost.

F-27

Depletion, depreciation and amortization

All costs of acquisition, exploration and development of oil and gas reserves, associated tangible plant and equipment costs (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 gross proven reserves as determined by independent engineers.

Costs of unproved properties and seismic costs on undeveloped land are initially excluded from oil and gas properties for the purpose of calculating depletion. When proven reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

The relative volumes of oil and natural gas reserves and production are converted to equivalent barrels of oil based on the relative energy content of each product on a 6 to 1 basis.

Depreciation of capital assets not related to oil and gas properties is provided using the declining balance method at rates between 20 and 30%. Leasehold improvements are amortized on a straight-line basis over the term of the lease.

Impairment

The Company applies a ceiling test to the capitalized costs of its oil and gas properties, net of future income taxes and asset retirement obligations, to ensure that the net carrying value does not exceed the estimated value of future net revenues from production of gross proven reserves plus undeveloped properties less future production-related general and administrative expenses, financing costs, site restoration and abandonment costs and income taxes. Any reduction in the net carrying value of oil and gas properties as a result of the ceiling test is charged to operations.

The calculation of future net revenues is based on sales prices, costs and regulations in effect at period end.

The carrying value of undeveloped properties (land and seismic data) is reviewed periodically and written down to net realizable value if impairment is determined.

(b) Asset Retirement Obligations

The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred and records a corresponding increase in the carrying value of the related long-lived asset. The fair value is determined through a review of engineering studies, industry guidelines, and management’s estimate on a site by site basis. The liability is subsequently adjusted for the passage of time, and is recognized as an accretion expense in the statement of earnings under asset retirement obligations. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the asset is amortized using the unit of production method based on estimated gross proven reserves as determined by independent engineers.

(c) Leasehold Inducements

Leasehold inducements are accounted for as a reduction of rental expense over the term of the related lease.

F-28

(d)   Revenue Recognition

Oil and natural gas sales are recognized as revenue when the commodities are delivered to purchasers.

Revenue from milestone payments and royalties is recognized when received.

(e)   Hedging and Forward Sales Contracts

In certain circumstances, fixed price commodity contracts or commodity derivative contracts are used to reduce the Company’s exposure to adverse fluctuations in commodity prices to protect future cash flow used to finance the Company’s capital expenditure program. Gains and losses relating to commodity derivative contracts which settle via net cash payment and that meet hedge criteria are recognized as part of natural gas sales concurrently with the hedged transaction. The Company does not enter into financial instruments for trading or speculative purposes.

The Company believes the derivative financial instruments are effective as hedges, both at inception and over the term of the instrument, as the term to maturity, the notional amount and the commodity price basis in the instruments all match the terms of the future revenue stream being hedged.

Realized and unrealized gains and losses associated with commodity derivative contracts which have been terminated or cease to be effective prior to maturity, are deferred as other current, or non-current, assets or liabilities on the balance sheet, as appropriate, and recognized in earnings in the period in which the underlying hedged transaction is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any realized or unrealized gain or loss on such derivative instrument is recognized in earnings.

(f)   Joint Ventures

Substantially all of the Company’s exploration, development and production activities are conducted jointly with others and, accordingly, these financial statements reflect only the Company’s proportionate interest in such activities.

F-29

(g)   Stock Based Compensation

Under the Company’s stock option plan, options to purchase common shares are granted to directors, officers, employees and consultants at current market prices. Options issued by the Company in 2003 are accounted for in accordance with the fair value method of accounting for stock-based compensation, and as such the cost of the option is charged to earnings with an offsetting amount recorded to contributed surplus, based on an estimate of the fair value determined using a Black-Scholes options pricing model. No compensation expense has been recorded on options issued in 2002 or 2001(see note 10).

(h)   Investments

Investments in marketable securities are recorded at the lower of cost and market value. At December 31, 2003, the investments had a quoted market value of $3,012,000.

The Company used the equity method of accounting for its investment in Oncolytics Biotech Inc. (“Oncolytics”) up until the end of the first quarter of 2002 when it no longer exerted significant influence over Oncolytics. Under this method of accounting, the Company included in its net earnings its share of the net earnings or losses of Oncolytics. Subsequent to this date, the investment was accounted for on a cost basis and accordingly, no net earnings or losses of Oncolytics have been included in net earnings subsequent to March 31, 2002 (see note 4(d)).

(i)   Future Income Taxes

The Company follows the liability method of accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse. Income tax expense for the period is the tax payable for the period and any change during the period in future income tax assets and liabilities. A valuation allowance is recorded to the extent that there is uncertainty regarding utilization of future tax assets.

(j)   Per Common Share Amounts

The Company uses the treasury stock method to determine the dilutive effect of stock options. This method assumes that proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the year.

(k)   Measurement Uncertainty

The amount recorded for depletion and depreciation of petroleum and natural gas properties, the provision for asset retirement obligation costs and the ceiling test calculation are based on estimates of gross proven reserves, production rates, commodity prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be significant.

(l)   Flow-through Common Shares

Resource expenditure deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. The estimated tax benefits transferred to shareholders are recorded as future income taxes and a reduction to share capital when the expenditures are renounced.

F-30

(m)   Research and Development

Research costs are expensed as incurred. Development costs that meet specific criteria related to technical, market and financial feasibility are capitalized.

(n)   Comparative Figures

Certain figures provided for 2002 have been reclassified to conform to the presentation adopted in 2003.

3.   CHANGES IN ACCOUNTING POLICIES

(a)   Asset Retirement Obligations

In 2003, the Company retroactively adopted the recommendations of the Canadian Institute of Chartered Accountants on accounting for asset retirement obligations. These recommendations replace the existing policy on future site restoration, and as a result, have been treated as a change in accounting policy.

The new pronouncement requires the Company to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying value of the related long-lived asset. This fair value is determined through a review of engineering studies, industry guidelines, and management’s estimate on a site by site basis. The liability is subsequently adjusted due to the passage of time, and is recognized as an accretion expense in the statement of earnings. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the capital asset is amortized using the unit of production method based on estimated gross proven reserves as determined by independent engineers.

The Company estimates the undiscounted cash flows related to asset retirement obligations, adjusted for inflation, to be incurred over the estimated reserve life of the underlying reserves will total approximately $4,972,000. The fair value at December 31, 2003 is $3,499,000 using a discount rate of 6% and an inflation rate of 2%. As at December 31, 2003, no funds have been set aside to settle this obligation.

As the Company did not have long-lived assets subject to retirement obligations as at December 31, 2002 and 2001, this change in accounting policy had no impact on the December 31, 2002 and 2001 financial statements. The effect of this change on the December 31, 2003 balance sheet was an increase in capital assets of $3,191,000 and the recognition of an asset retirement obligation of $3,499,000. Accretion expense of $100,000 was included in production expense for the year ended December 31, 2003. The change in accounting for asset retirement obligations as compared to the site restoration approach resulted in an increase in net earnings of $217,000 for the year ended December 31, 2003 ($0.01 per share).

(b)   Stock Based Compensation

Effective January 1, 2003, the Company adopted the recommendations of the Canadian Institute of Chartered Accountants on accounting for stock based compensation. Under this new pronouncement, stock based compensation expense is recorded for all stock options granted on or after January 1, 2003. As permitted by the standard, the Company applied the change prospectively. The pro forma earnings impact of the stock based compensation expense for stock options granted prior to January 1, 2003 is disclosed in note 10.

For the year ended December 31, 2003, the impact of the adoption of this standard on the financial statements as at December 31, 2003 was a decrease in net earnings of $132,000 ($0.01 per share) and a corresponding increase in contributed surplus.

F-31

4. BUSINESS ACQUISITIONS AND DISPOSITIONS

(a) 1022971 Alberta Ltd.

On March 31, 2003 the Company acquired all of the shares of 1022971 Alberta Ltd. (“1022971”) for a nominal amount and the Company was assigned an option to purchase up to a 49% interest in certain oil and gas properties west of the 4th meridian (“W4M Properties”) owned by Southward Energy Ltd. (“Southward”). On April 30, 2003, 1022971 acquired all of the shares of Southward. Immediately thereafter, Southward sold its oil and gas properties, excluding a 1% undivided interest in the W4M Properties and a 100% interest in seismic data, to an independent third party.

On June 30, 2003, the Company exercised its option to purchase a 49% interest in the W4M Properties. Further on June 30, 2003, the Company purchased the 1% undivided interest in the W4M Properties of Southward and the non-cash working capital of Southward was conveyed to the Company. Also on June 30, 2003, all of the shares of 1022971, which included Southward and all of its subsidiaries, were sold for nominal consideration to an independent third party.

The resultant acquisition of a 50% interest in the W4M Properties on June 30, 2003 has been accounted for using the purchase method of accounting. The results of operations for the W4M Properties have been included in the financial statements since June 30, 2003.

The following table summarizes the estimated fair value of the assets and liabilities assumed at the date of acquisition:


Capital assets	$	70,514
Asset retirement obligations		(2,833	)
Non-cash working capital		3,656

Cash cost	$	71,337

The Company has agreed to indemnify the purchaser of Southward for income tax and legal expenses to a maximum amount of $1 million for matters arising prior to the April 30, 2003 acquisition of Southward.

(b) 1053638 Alberta Ltd. and 1053639 Alberta Ltd.

On August 14, 2003, the Company acquired all of the shares of 1053638 Alberta Ltd. and 1053639 Alberta Ltd., seismic data companies. On August 19, 2003, the Company sold all of the shares of 1053638 Alberta Ltd. The net acquisitions were accounted for by the purchase method and the purchase price was allocated as follows:


Allocation of purchase price:
Capital assets	$	1,200

Cash Cost	$	1,200

The disposition of 1053638 Alberta Ltd. did not result in any gain or loss to the Company. On December 310, 2003, 1053639 Alberta Ltd. was amalgamated with the Company.

F-32

(c) Pointwest Energy Inc.

On December 30, 2003 the Company acquired all of the shares of Pointwest Energy Inc. (“Pointwest”), a privately held oil and gas company. The acquisition was accounted for by the purchase method and the purchase price was allocated as follows:


Allocation of purchase price:
Capital assets	$	89,363
Bank debt		(16,429	)
Asset retirement obligations		(518	)
Non-cash working capital		(5,169	)

Cash cost	$	67,247

On December 30, 2003, Pointwest was amalgamated with the Company.

(d) Oncolytics Biotech Inc.

The Company acquired all of the issued and outstanding common shares of Oncolytics Biotech Inc. (“Oncolytics”) on April 12, 1999. Oncolytics subsequently issued common shares which reduced the Company’s ownership interest to 38.6% at December 31, 2000. During 2001, Oncolytics issued common shares which further reduced the Company’s ownership interest and resulted in a gain on dilution of $357,000. As at December 31, 2001, the Company held 6,255,800 common shares of Oncolytics Biotech Inc.

On May 7, 2002 approval was received from both the shareholders of the Company and the shareholders of Oncolytics for the distribution of not less then 4,000,000 Oncolytics shares to the shareholders of the Company on a pro rata basis. On May 8, 2002 the Company received approval from the Court of the Queen’s Bench of Alberta to distribute these Oncolytics shares and the distribution of 4,000,235 Oncolytics shares was made effective May 15, 2002. The deemed value of these shares on the date of distribution, net of legal fees with respect to the transaction, was $11,600,000 resulting in a gain on distribution of $8,325,000. The transaction was marked to market and accounted for as a return of capital (see Note 9). As part of this transaction the Company’s holding of 1,500,000 million shares in BCY Life Sciences Inc. was transferred to Oncolytics. No value had been assigned to these shares in the accounts of the Company and no gain or loss was recorded as a result of the transaction. The market value of the BCY shares on May 15, 2002 was $300,000.

The Company had used the equity method of accounting for its investment in Oncolytics Biotech Inc. up until the distribution of the majority of its holding in Oncolytics on May 15, 2002. Under this method of accounting, the Company included in its net earnings its share of the net earnings or losses of Oncolytics. Upon further review of the facts surrounding the distribution of the Oncolytics shares, the Company has concluded that it should have ceased to equity account for Oncolytics at the end of the first quarter of 2002 when it no longer exerted significant influence over Oncolytics. If the Company had ceased equity accounting for its investment in Oncolytics at that time, Hawker would not have recorded the portion of Oncolytics’ second quarter loss included in its statements. To reflect this correction, the Company has restated its financial statements for the year ended December 31, 2002 by decreasing the share of loss from equity investment in Oncolytics and decreasing the gain on the subsequent sale and distribution of Oncolytics shares by $157,000 resulting in no change to reported net earnings for the year. The balance sheet and cash flows for 2002 were not affected by this change.

During the year ended December 31, 2002, the Company sold 2,255,565 common shares in Oncolytics for net proceeds of $6,898,000 resulting in a gain on sale of $4,742,000. As at December 31, 2002 the Company did not hold any common shares of Oncolytics.

5. ASSETS HELD FOR SALE

Assets held for sale are comprised of the pharmaceutical manufacturing facility and related manufacturing equipment associated with the former biotech operations of the Company. During 2003, manufacturing equipment with a carrying value of $940,000 was sold and the Company wrote down the carrying value of the remaining assets held for sale by $145,000. The assets held for sale are recorded at the lower of carrying value and market value. Market value was based on estimated value as determined by independent realty advisors.

F-33

6. CAPITAL ASSETS


			2003
			Accumulated
			Depletion and
	Cost		Depreciation		Carrying Value
Gas properties	$	175,631	$	8,916	$	166,715
Other		295		20		275

	$	175,926	$	8,936	$	166,990


			2002
			Accumulated
			Depletion and
	Cost		Depreciation		Carrying Value
Other	$	526	$	503	$	23

Unproved properties and seismic related to the W4M Properties amounting to $16,122,000 have been excluded from the depletion and depreciation calculation for 2003. No depletion and depreciation has been recorded on the Pointwest properties as they were acquired December 30, 2003. Future development costs on proven undeveloped reserves of $1,269,000 are included in the depletion and depreciation calculation.

At December 31, 2003, the Company capitalized $564,000 of overhead directly related to exploration and development activities.

7. BANK LOAN

The Company has a $54 million extendible revolving term credit facility from a Canadian chartered bank. This facility bears interest at rates varying from Canadian prime rate or U.S. base rate of such bank to the Canadian prime rate or U.S. base rate plus 75 basis points, payable monthly in arrears. The Company may also borrow by way of bankers’ acceptances, which are subject to a stamping fee, or by way of LIBOR based loans which are subject to an interest rate spread payable to the bank. The loan is a revolving facility until June 30, 2004 with annual extension periods available at the bank’s discretion. After the revolving phase, the facility becomes a term facility payable in full one year from the date the revolving facility is terminated. This facility is subject to semi-annual review and re-determination of the Company’s borrowing base by the bank, with the next review to occur by March 31, 2004. So long as the loan remains revolving and the borrowing base supports the facility outstanding, there are no repayment requirements.

The Company also has a $10 million non-revolving bridge facility from the same Canadian chartered bank. This bridge facility, available to the Company solely for the acquisition of Pointwest, was fully drawn upon as at December 31, 2003. The bridge facility bears interest at rates varying from Canadian prime rate plus 250 basis points, payable monthly in arrears. The Company may also borrow by way of bankers’ acceptances that are subject to a stamping fee payable to the bank. The bridge facility is repayable in full on or prior to September 30, 2004.

While any amounts are outstanding under the bridge facility, the loan margins on both the extendible revolving term credit facility and the bridge facility will be increased by (i) 25 basis points effective May 1, 2004; (ii) 50 basis points effective June 1, 2004; (iii) 100 basis points effective July 1, 2004; (iv) 150 basis points effective August 1, 2004; and (v) 200 basis points effective September 1, 2004.

Collateral pledged for the facilities consists of a first floating charge demand debenture in the amount of $150 million over all of the property of the Company.

The effective interest rate on the amounts outstanding under the facility at December 31, 2003 was 5.25%.

At December 31, 2003, irrevocable standby letters of credit which guarantee certain natural gas transportation arrangements had been issued for a total amount of $311,000.

F-34

8.   ALBERTA HERITAGE FOUNDATION GRANT

Pursuant to the terms of a technology commercialization agreement pertaining to pharmaceutical drug development, the Company received a grant from the Alberta Heritage Foundation for Medical Research (“AHFMR”) during 1995. The Company was required to repay the amount advanced of $387,000 plus a royalty equivalent to the amount initially received. Any required repayment and royalty was based on gross sales of SYNSORB related products commencing January 1, 2000 with payments equal to the lesser of 5% of gross sales or $100,000 per annum commencing 90 days after January 1, 2001. Due to the conversion of the Company into an oil and gas enterprise and the nascent stage of the SYNSORB technology, the AHFMR accepted a royalty payment of $18,550 during 2003 in exchange for a full release of Hawker from the terms of the technology commercialization agreement.

9.   SHARE CAPITAL

(a)   Authorized:

  Unlimited number of voting common shares without par value.

  Unlimited number of non-voting class A common shares without par value.

  Unlimited number of preferred shares to be issued in series.

(b)   Common Shares Issued


	2003					2002					2001
	No. of					No. of					No. of
	Shares		Amount			Shares		Amount			Shares		Amount
Balance, beginning of year		4,959,937	$	12,741			4,959,937	$	84,271			4,944,187	$	84,145
Reduction of stated capital		—		—			—		(59,896	)		—		—
Issued for cash		28,461,000		105,633			—		—			—		—
Share issue costs		—		(6,826	)		—		—			—		—
Issued on debenture and warrant conversion		2,152,465		1,302			—		—			—		—
Issued for services received		148,798		90			—		—			—		—
Issued for cash on exercise of options		275,000		192			—		—			15,750		126
Tax benefits renounced		—		(5,271	)		—		—			—		—
Return of capital on distribution of Oncolytics shares		—		—			—		(11,646	)		—		—
Issuance of stock options for services		—		—			—		12			—		—

Balance, end of year		35,997,200	$	107,861			4,959,937	$	12,741			4,959,937	$	84,271

F-35

2003

2002

2001

No. of

Shares

Amount

Shares

Amount

Shares

Amount

Balance, beginning of year

—

Issued on debenture and warrant conversion

3,874,437

2,343

—

Balance, end of year

3,874,437

2,343

—

(d) Contributed Surplus


	2003
Balance, beginning of year	$	—
Stock based compensation		132

Balance, end of year	$	132

(e)   Issue of Debentures and Warrants

Pursuant to various financing agreements entered into April 3, 2003, the Company raised $3,645,000 through the issue of 430,493 Series A Debentures for $3,616,000, 430,493 Series A Warrants for $12,000, 2,152,465 voting preferred shares for $6,000 and 3,874,437 non-voting preferred shares for $11,000.

Each Series A Warrant entitled the holder thereof to purchase five common shares and nine Class A common shares on the concurrent surrender of the warrant, five voting preferred shares, nine non-voting preferred shares, and one Series A Debenture. On May 29, 2003, immediately after the issue of a receipt for the prospectus offering common shares for sale and issue, the Series A Warrants were exercised and the Company issued 2,152,465 common shares and 3,874,437 Class A common shares upon the surrender of the voting and non-voting preferred shares and Series A Debentures.

(f)   Share Consolidation

On May 7, 2002, the shareholders of the Company approved the consolidation of the common shares on the basis of one new common share being issued for every eight previously issued and outstanding common shares. All outstanding share and option numbers reflect the one for eight consolidation. The consolidated shares began trading on May 16, 2002. Simultaneously with the share consolidation was the distribution of the 4,000,235 shares in Oncolytics to the shareholders of the Company. This distribution was accounted for as a capital transaction and accordingly, the stated capital of the common shares was reduced by $11,646,000.

(g)   Reduction of Stated Capital

Pursuant to the Plan of Arrangement ratified by shareholders of the Company at the May 7, 2002 Annual and Special Meeting, the stated capital of the Company’s shares was reduced to the net realizable value of the Company’s assets as at May 7, 2002.

(h)   Flow-Through Shares

During 2003, the Company issued common shares on a flow-through basis for gross proceeds of $15,225,000 to finance certain oil and gas expenditures to be incurred in 2004. The renouncement of these expenditures was made to the purchasers of these shares effective December 31, 2003 and accordingly, share capital has been reduced by the amount of the tax benefits associated with these expenditures. The corresponding future tax liability has also been recognized in the current year.

F-36

(i) Stock Options

The Company has a stock option plan that provides for the issuance of options to its directors, officers, employees and non-employees to acquire up to 1,181,513 common shares. The dates on which options vest are set by the board of directors at the time of grant. The exercise price of an option granted is the closing price of the Company’s stock on the last trading date prior to the grant date. The dates on which options expire are also set by the board of directors at the time of grant and cannot exceed ten years. The Company has issued stock options to acquire common shares through its stock option plan of which the following are outstanding at December 31, 2003:


	2003					2002					2001
				Weighted					Weighted					Weighted
				average					average					average
				exercise					exercise					exercise
	Number of			price		Number of			price		Number of			price
	Options			$		Options			$		Options			$
Outstanding at beginning of the year		330,565			9.80		244,440			40.88		275,877			49.60
Granted		428,000			3.66		275,000			0.70		65,625			12.88
Exercised		(275,000	)		0.70		—			—		—			—
Expired		(12,500	)		87.20		(6,250	)		68.00		—			—
Forfeited		(27,064	)		52.20		(182,625	)		35.76		(97,062	)		46.64

Outstanding at year end		444,001			4.74		330,565			9.80		244,440			40.88

Options exercisable at end of year		15,751			34.27		329,065			9.80		212,550			45.04

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


			Weighted
	Number		average		Weighted		Number
	outstanding		remaining		average		exercisable		Weighted
	December 31,		contractual		exercise		December 31,		average
	2003		life (years)		price		2003		exercise price
Range of exercise prices
$3.00 to $4.00		365,000		4.44	$	3.57		—		—
$4.01 to $5.00		60,000		4.89	$	4.08		—		—
$5.01 to $9.00		3,000		4.67	$	5.20		—		—
$9.01 to $30.00		8,188		2.33	$	20.06		7,938	$	20.42
$30.01 to $90.00		7,813		4.30	$	48.33		7,813	$	48.33

		444,001		4.46	$	4.74		15,751	$	34.27

For the year ended December 31, 2003, no stock options were granted to non-employees. The Company has undertaken to facilitate the surrender of out-of-the-money options that were issued in previous years when the Company conducted pharmaceutical drug development. Subsequent to December 31, 2003, the Company granted options to purchase 64,600 common shares at a weighted average price of $5.48, which expire during the first quarter of 2009. Also subsequent to December 31, 2003, options to purchase 15,000 common shares at $3.45 were forfeited.

(j) Per Share Amounts

The weighted average number of common shares and Class A common shares outstanding during the year ended December 31, 2003 of 17,123,542 (2002: 4,959,937; 2001: 4,955,199) were used to calculate net earnings per common share. For the year ended December 31, 2003, the exercise price of the outstanding stock options exceeded the average market price of the common shares making the options anti-dilutive. For the year ended December 31, 2002, the respective exercise price of the stock options and warrants exceeded the average market price of the common shares making the options and warrants anti-dilutive. For the year ended December 31, 2001, option and warrant conversions were not included in the computation of diluted earnings per share because the effect on the net loss for the year of the issue of additional shares on the conversions would be anti-dilutive.

F-37

10. STOCK BASED COMPENSATION

Options granted after January 1, 2003 are accounted for using the fair value method. The fair value of common share options granted in 2003 is estimated to be $789,000 as at the date of grant using the Black-Scholes option pricing model and the following weighted average assumptions:


	2003
Risk-free interest rate (%)		3.79
Expected life (years)		4.00
Expected volatility (%)		54.59
Expected dividend yield (%)		0

The estimated fair value of the options is amortized to expense over the options’ vesting period on a straight-line basis. For the year ended December 31, 2003, stock based compensation expense of $132,000 was included in general and administrative expenses.

Had the fair value based method of accounting for stock based compensation been used for options granted in 2002, the Company’s net earnings and net earnings per share for the year ended December 31, 2002 would have been reduced to the pro forma amounts indicated below:


	2002
Net earnings
As reported	$	3,766
Pro forma	$	3,646
Basic and diluted net earnings per common share
As reported ($/share)	$	0.76
Pro forma ($/share)	$	0.74

The pro forma amounts shown above do not include the compensation costs associated with stock options granted prior to January 1, 2002. The fair value of common share options granted in 2002 was estimated to be $120,000 as at the date of grant using the Black-Scholes option pricing model and the following assumptions:


	2002
Risk-free interest rate (%)		2.89
Expected life (years)		1.00
Expected volatility (%)		1.97
Expected dividend yield (%)		0

All stock options issued in 2002 were exercised in 2003.

F-38

11. INCOME TAXES

The provision for income taxes recorded in the financial statements differs from the amount which would be obtained by applying the statutory income tax rate to the net earnings (loss) before tax as follows:


	2003			2002			2001
Earnings (loss) before tax	$	(2,612	)	$	3,766		$	(24,544	)
Statutory Canadian corporate tax rate		40.74	%		39.24	%		42.12	%

Anticipated tax expense (recovery)		(1,064	)		1,478			(10,338	)
Non-deductible Crown payments		945			—			—
Resource allowance		(878	)
Recognition of loss carryforward previously unrecognized		(5,271	)		—			—
Effect of tax rate change		519			—			—
Gain on dilution of investment in Oncolytics		—			—			(75	)
Taxable income from investment in Oncolytics		—			—			421
Non-taxable portion of capital gain		—			(2,536	)		(633	)
Non-deductible portion of equity loss		—			92			—
Non-deductible expenses		—			3			26
Future tax assets valuation allowance		478			963			9,043

Future income tax recovery	$	(5,271	)	$	—		$	(1,556	)

Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Company’s future income tax assets and liabilities are as follows:


	2003			2002
Future tax liabilities:
Net book value of capital assets in excess of tax pools	$	(10,726	)	$	—
Future tax assets:
Tax pools in excess of net book value of capital assets		—			6,422
Non-capital loss carryforwards		6,243			11,984
Scientific research and development pools		7,784			7,896
Share issue costs		2,006			400
Attributed Canadian royalty income		268			—
Asset retirement obligation		1,212			—

Net future tax assets		6,787			26,702
Valuation allowance		(6,787	)		(26,702	)

Net future taxes	$	—		$	—

The Company has non-capital losses for income tax purposes of approximately $18,035,000 which are available for application against future taxable income and which expire in the following years:


2006	$	1,448
2007		5,103
2008		11,484

	$	18,035

The income tax benefit of these losses has not been recognized in the financial statements, as reflected in the valuation allowance. The Company also has approximately $5,700,000 of unclaimed investment tax credits available to reduce future years’ income taxes payable.

F-39

12.   RELATED PARTY TRANSACTIONS

A director of the Company is a partner of a law firm that was paid $2,150,000 for legal services for the period from the date elected as a director, April 3, 2003, to December 31, 2003. The fees charged were based on standard rates and time spent on Company matters.

13.   FINANCIAL INSTRUMENTS

(a)   Fair Value

The Company has financial instruments consisting of accounts receivable, investments, accounts payable and bank loans. The carrying value of these instruments approximates fair value unless otherwise stated.

Pursuant to the exercise of the option to purchase the W4M properties (Note 4), the Company acquired an interest in forward sales contracts and financial hedging contracts with respect to production from the purchased properties as follows:


Transaction Type	Volume (GJ/d)	Contract Price (GJ/d)	Expiry
Costless Collar	4,830	$6.36 - $7.15	March 31, 2004
Fixed	1,610	$6.76	March 31, 2004
Cogeneration Fuel Supply	263	$1.959 - $2.217	October 31, 2008
Daily Declining Profile	841⁽¹⁾	Netback⁽²⁾	October 31, 2011
Reserve Based	101	Netback⁽³⁾	Life of reserves

Based on dealer quotes, had these contracts been closed on December 31, 2003, a loss of $1,467,000 would have been realized.

Notes:

(1) The Company’s obligations under this contract will, on November 1 of each succeeding year, decline to the following:


Date		Obligation (GJ/d)
November 1, 2004		724
November 1, 2005		623
November 1, 2006 and thereafter		568

(2) TransCanada Pipelines Limited netback pricing.

(3) Progas Limited netback pricing.

The following financial hedging contracts were entered into subsequent to December 31, 2003:


Transaction Type	Volume (GJ/d)	AECO Price (GJ/d)	Term
Collar	5,000	$5.50 - $6.35	April 1, 2004 to October 31, 2004
Collar	8,000	$5.50 - $6.40	April 1, 2004 to October 31, 2004
Collar	5,000	$5.50 - $6.36	April 1, 2004 to October 31, 2004
Fixed Price Swap	5,000	$5.745	April 1, 2004 to June 30, 2004
Fixed Price Swap	5,000	$5.745	August 1, 2004 to October 31, 2004
Fixed Price Swap	5,000	$5.7725	April 1, 2004 to October 31, 2004

F-40

(b) Credit Risk

A substantial portion of the Company’s accounts receivable are with entities in the oil and gas industry. The Company generally extends unsecured credit to these companies, and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions and may accordingly impact the Company’s overall credit risk. Management believes the risk is mitigated by the size, reputation and diversified nature of the companies to which they extend credit. The Company has not previously experienced any material credit losses on the collection of receivables.

(c) Interest Rate Risk

The Company is exposed to interest rate risk in relation to interest expense on its revolving credit facility and non-revolving bridge facility.

14. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Changes in non-cash working capital were comprised of the following:


	2003			2002			2001
Accounts receivable	$	(11,550	)	$	35		$	135
Prepaids and other current assets		(1,669	)		(23	)		(34	)
Investments		(2,500	)		—			—
Accounts payable and accrued liabilities		23,670			(4,791	)		3,541
Less working capital deficiency on acquisitions		(1,513	)		—			—

Net change	$	6,438		$	(4,779	)		3,642

Net change by activity:
Operating	$	5,660		$	(4,779	)	$	3,642
Investing		806			—			—
Financing		(28	)		—			—

Net change	$	6,438		$	(4,779	)	$	3,642

Additional information:


	2003		2002		2001
Cash interest paid	$	495	$	71	$	787
Cash taxes paid		—		10		86

15. CONTINGENCIES

The Company, in the normal course of operations, is subject to a variety of legal and other claims against the Company. Management and the Company’s legal counsel evaluate all claims on their apparent merits, and accrue management’s best estimate of the likely costs to satisfy such claims. Management believes that the outcome of legal and other claims filed against the Company will not have a significant impact on the Company’s financial position, operations or cash flows.

The Company indemnifies its directors and officers against any and all claims or losses reasonably incurred in the performance of their service to the Company to the extent permitted by law. The Company has acquired and maintains liability insurance for its directors and officers.

F-41

16. COMMITMENTS

The Company has committed to purchase seismic data in the amount $225,000 during the first six months of 2004.

The Company is committed to payments under operating leases for office space as follows:


2004	$	611
2005		718
2006		413
2007		385
2008		385

	$	2,512

17.   SUBSEQUENT EVENTS

On March 17, 2004, the Company acquired 100% of the shares of Zorin Exploration Ltd. for aggregate consideration of $7.4 million comprising $1.5 million of cash and $5.9 million of equity representing 1,150,000 common shares.

18.   RECONCILIATION OF CANADIAN AND UNITED STATES
  GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The financial statements are prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) which, in most respects, conform to United States generally accepted accounting principles (“US GAAP”). Significant differences between Canadian GAAP and US GAAP are as follows:


				2003			2002		2001
	Notes			$			$		$
Net earnings (loss) - Canadian GAAP					2,314			3,766		(22,988	)
Derivatives and other financial instruments		(a	)		(1,467	)		—		—
Investments		(b	)		512			—		—
Share of loss from equity investment in Oncolytics		(c	)		—			314		1,831
Gain on sale of Oncolytics shares		(c	)		—			5,431		476
Gain on dilution of investment in Oncolytics		(c	)		—			—		(357	)
Amortization		(d	)		—			—		671
Tax expense on issue of flow-through shares		(f	)		(1,936	)		—		—
Depletion and depreciation		(g	)		(17,243	)		—		—

Net earnings (loss) and comprehensive earnings (loss) - US GAAP					(17,820	)		9,511		(20,367	)
Net earnings (loss) per common share - US GAAP					(1.04	)		1.92		(4.11	)

Balance sheet items in accordance with US GAAP are as follows:


				December 31, 2003						December 31, 2002
				Canadian			US			Canadian			US
				GAAP			GAAP			GAAP			GAAP
(in thousands of dollars)	Notes			$			$			$			$
Investments		(b	)		2,500			3,012			—			—
Derivative financial instruments		(a	)		—			1,467			—			—
Capital assets		(g	)		166,990			149,747			—			—
Share capital		(f)			110,204			112,140			12,741			12,741
Deficit		(a),(b), (f), (g)			(6,879	)		(27,013	)		(9,193	)		(9,193	)

F-42

(a)   Derivative Financial Instruments

The Company has designated, for Canadian GAAP purposes, its derivative financial instruments as hedges of anticipated revenue. In accordance with Canadian GAAP, payments or receipts on these contracts are recognized in income concurrently with the hedged transaction. The fair values of the contracts deemed to be hedges are not reflected in the financial statements.

For US purposes, the Company has adopted Statement of Financial Accounting Standards No. 133, as amended, Accounting for Derivative Instruments and Hedging Activities. With the adoption of this standard, all derivative instruments are recognized on the balance sheet at fair value. The standard requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Management has not designated any of the currently held financial instruments as hedges for US GAAP purposes and accordingly, these derivatives have been recognized on the balance sheet at fair value with the change in their value recognized in earnings.

Under US GAAP for the year ended December 31, 2003, additional expense of $1,467,000 before and after taxes (2002: Nil; 2001: Nil) would have been recorded.

(b)   Investments

Under US GAAP, equity securities that are bought and held principally for the purpose of selling them in the short term are classified as trading securities and reported at fair value with unrealized gains and losses included in earnings. Under Canadian GAAP, these gains and losses are not recognized in earnings until the security is sold. As at December 31, 2003, the Company had unrealized holding gains of $512,000.

(c)   Accounting for Oncolytics Shares

US GAAP differences result when accounting for Oncolytics Shares as follows:

i. During 1999, the Company acquired Oncolytics for $2,500,000. Under US GAAP, the purchase price would have been allocated to the following:


(in thousands of dollars)	$
Research and development		3,615
Future tax liability		(1,115	)

		2,500

The research and development had no alternative future uses. Under Canadian GAAP, the research and development has to be capitalized, however under US GAAP, this amount would have been charged to expense and accordingly the investment in Oncolytics had no accounting cost basis under US GAAP.

ii. Under Canadian GAAP, a gain may be realized when a development stage subsidiary issues shares from treasury diluting the parent company’s ownership. US GAAP does not allow the recognition of a gain on dilution of a development stage subsidiary.

iii. The write off of the acquisition costs of the Oncolytics shares, as described in (i), results in a nil accounting cost for the shares under US GAAP. The accounting cost for Canadian GAAP subsequently increases for the dilution gains recognized and decreases to reflect the Company’s share of loss from equity accounting under Canadian GAAP. Adjustments are made under US GAAP to eliminate the effect of dilution gains, equity losses and the resulting impact on gains recognized on the sale of Oncolytics shares.

F-43

(d) Depreciation on Building

Under US GAAP, amortization of the Company’s building must commence when it is physically ready for use. Under Canadian GAAP, amortization begins when commercial use of the building begins. On January 1, 2000, the Company’s building was physically ready for use, however commercial use had not commenced. Therefore $671,000 of additional amortization is recorded under US GAAP in 2000. In 2001, the building was written down to its estimated net realizable value. Under US GAAP, given amortization was recorded in 2000, the writedown in 2001 has been reduced by $671,000. The building was held for sale during 2002 and 2003 and was written down to its estimated net realizable value at December 31, 2002 and 2003. Therefore, in 2002 and 2003, there was no difference in accounting under US GAAP.

(e) Stock Based Compensation

For US reporting purposes, the statement of Financial Accounting Standard No.123 “Accounting for Stock Based Compensation” (“SFAS 123”) requires the reporting of pro forma amounts for compensation expense that would have been recorded for the issuance of share options using a fair value option pricing model. On January 1, 2002, the Company adopted the new CICA standard for stock-based compensation, resulting in the pro forma disclosure contained in Note 10. The Company has applied this change prospectively commencing on the date of adoption, effectively eliminating the US GAAP difference associated with this accounting.

The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions:


	2001
Risk free interest rate		5.13	%
Dividend yield		0	%
Volatility factors of expected market price		119	%
Weighted average expected life of the options	1 year

Pro forma disclosures of loss and loss per common share are presented below as if the Company had adopted the cost recognition requirements under SFAS 123. The compensation cost for the stock-based compensation was approximately $382,495 in 2001.


		2001
(in thousands of dollars)		$
Loss – US GAAP	As reported		(20,367	)
	Pro forma		(20,749	)
Loss per common share – US GAAP	As reported ($/share)		(4.11	)
	Pro forma ($/share)		(4.19	)

(f) Flow-Through Shares

Canadian GAAP requires that any cost of future income taxes arising when an entity renounces the deductibility of expenditures to an investor in flow-through shares should be accounted for as a cost of issuing the shares resulting in a reduction of share capital. Under US GAAP, the proceeds from the issuance of flow-through shares should be allocated between the offering of shares and the sale of tax benefits. The allocation is made based on the difference between the quoted price of the existing shares and the amount the investor pays for the shares. A liability is recognized for this difference. The liability is reversed when tax benefits are renounced and a deferred tax liability is recognized at that time. The difference between the amount of the deferred tax liability and the liability recognized on issuance is recorded as deferred income tax expense therefore increasing the deficit and increasing the amount of share capital.

(g) Impairments

Under both US and Canadian GAAP, property, plant and equipment must be assessed for potential impairments. Under US GAAP, if the sum of the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs), discounted at ten percent, is less than the net capitalized costs (net of deferred income taxes), the excess is charged to expense. As disclosed in note 2, under Canadian GAAP, the impairment loss is the difference between the net carrying value of the asset and the estimated value of future net revenues. The resulting differences in recorded carrying values of impaired assets result in further differences in depreciation and depletion expense in subsequent years.

F-44

INDEX TO EXHIBITS


Exhibit
Number		Description
1.1⁽¹⁾		Articles of Incorporation of the Company dated February 14, 1994

1.2⁽¹⁾		Articles of Amendment of the Company dated March 31, 1994.

1.3⁽¹⁾		Articles of Amendment of the Company dated July 12, 1994.

1.4⁽¹⁾		Articles of Arrangement of the Company dated May 8, 2002.

1.5⁽¹⁾		Restated Articles of Incorporation of the Company dated May 8, 2002.

1.6⁽¹⁾		Articles of Amendment and Restated Articles of the Company dated April 3, 2003.

1.7⁽¹⁾		Articles of Amendment and Restated Articles of the Company dated April 3, 2003.

1.8		Articles of Amalgamation and Registration Statement of the Company dated December 30, 2003

1.9		Articles of Amalgamation and Registration Statement of the Company dated December 30, 2003

1.10		Articles of Amalgamation and Registration Statement of the Company dated December 31, 2003

1.11		Articles of Amendment and Restated Articles of the Company dated May 3, 2004

1.12⁽¹⁾		By-Law Number 1 of the Company dated March 31, 1994.

4.1⁽¹⁾		Stock Option Plan of the Company

12.1		Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxly Act of 2002

12.2		Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxly Act of 2002

13.1		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxly Act of 2002

13.2		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxly Act of 2002

Note:

(1) Previously filed by the Company.


GLOSSARY			2
ABBREVIATIONS			3
CONVERSION			3
FORWARD-LOOKING STATEMENTS			3
PART I			4
Item 1. Identity of Directors, Senior Management and Advisers			4
Item 2. Offer Statistics and Expected Timetable			4
Item 3. Key Information			4
Item 4. Information on the Company			11
Item 5. Operating and Financial Review and Prospects			28
Item 6. Directors, Senior Management and Employees			34
Item 7. Major Shareholders and Related Party Transactions			39
Item 8. Financial Information			41
Item 9. The Offer and Listing			41
Item 10. Additional Information			42
Item 11. Quantitative and Qualitative Disclosures About Market Risk			52
Item 12. Description of Securities Other than Equity Securities			52
PART II			53
Item 13. Defaults, Dividend Arrearages and Delinquencies			53
Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds			53
Item 15. Controls and Procedures			53
Item 16A. Audit Committee Financial Expert			53
Item 16B. Code of Ethics			53
Item 16C. Principal Accountant Fees and Services			54
Item 16D. Exemptions from the Listing Standards for Audit Committees			54
Item 16E. Purchases of Equity Securities by the Issuer and affiliated purchases			54
PART III			55
Item 17. Financial Statements			55
Item 18. Financial Statements			56
Item 19. Exhibits			56
CERTIFICATIONS
FINANCIAL STATEMENTS			F-1
INDEX TO EXHIBITS
Articles of Amalgamation and Registration Statements of the Company dated December 30, 2003
Articles of Amalgamation and Registration Statement of the Company dated December 30, 2003
Articles of Amalgamation and Registration Statement of the Company dated December 30, 2003
Articles of Amendment and Restated Articles of the Company dated May 3, 2004
Certification of the CEO Pursuant to Section 302
Certification of the CFO pursuant to Section 302
Certification of the CEO pursuant to Section 906
Certification of the CFO pursuant to Section 906

•		the quantity of the Company’s reserves;

•		oil and natural gas production levels;

•		capital expenditure programs;

•		projections of market prices and costs;

•		supply and demand for oil and natural gas;

•		expectations regarding the Company’s ability to raise capital and to continually add to reserves through acquisitions and development; and

•		treatment under governmental regulatory regimes.

•		volatility in market prices for oil and natural gas;

•		liabilities and risks inherent in oil and gas operations;

•		uncertainties for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel;

•		incorrect assessments of the value of acquisitions; and

•		geological, technical, drilling and processing problems.

(1)		Prior to June 2003, the Company was not engaged in the exploration, development or production of oil or gas and did not hold any interests in any oil or gas properties.

(2)		“Gross wells” means the total number of wells in which the Company has an interest.

(3)		“Net wells” means the number of gross wells multiplied by the Company’s working interest therein.

(4)		“Dry well” means a well which is not a productive well or a service well. A productive well is a well which is capable of producing oil and gas in commercial quantities or in quantities considered by the operator to be sufficient to justify the costs required to complete, equip and produce the well. A service well means a well such as a water or gas-injection, water-source or water-disposal well. Such wells do not have marketable reserves of crude oil or natural gas attributed to them but are essential to the production of the crude oil and natural gas reserves.

		(1)“Gross Acres” means the total acres in which the Company has an interest.

		(2)“Net Acres” means the total acres in which the Company has an interest multiplied by the working interest therein.

(2)		TransCanada Pipelines Limited netback pricing.

(3)		Progas Limited netback pricing.

(1)		Information as to Common Shares beneficially owned, not being within the knowledge of the Company, has been furnished by the respective officers and directors.

(2)		Of these Common Shares, 3,641,286 are owned by Matco Capital Ltd. Matco Capital Ltd. is controlled by Matco Investments Ltd. and Matco Investments Ltd. is controlled by Ronald Mathison. To the knowledge of the Company, the only entities with an interest of greater than 10% in Matco Capital Ltd. are Matco Investments Ltd. and Mountain Moon Capital Inc. To the knowledge of the Company, the only shareholder holding, directly or indirectly, greater than 10% of the outstanding shares of Matco Investments Ltd. is Ronald Mathison and the only shareholders holding, directly or indirectly, greater than 10% of Mountain Moon Capital Inc. are members of Martin Lambert’s immediate family. In addition to his beneficial ownership of Common Shares resulting from his control of Matco Investments Ltd., Mr. Mathison beneficially owns 13,900 Common Shares as a result of shared power to dispose of such shares.

(3)		Excludes 3,641,286 Common Shares held by Matco Capital Ltd. Matco Capital Ltd. is controlled by Matco Investments Ltd. and Matco Investments Ltd. is controlled by Ronald Mathison. To the knowledge of the Company, the only entities with an interest of greater than 10% in Matco Capital Ltd. are Matco Investments Ltd. and Mountain Moon Capital Inc. To the knowledge of the Company, the only shareholder holding, directly or indirectly, greater than 10% of the outstanding shares of Matco Investments Ltd. is Ronald Mathison and the only shareholders holding, directly or indirectly, greater than 10% of Mountain Moon Capital Inc. are members of Martin Lambert’s immediate family.

(4)		Does not include options to acquire 100,000 Common Shares held by this individual.

(5)		Does not include and options to acquire 75,000 Common Shares held by this individual.

(1)		Matco Capital Ltd. is controlled by Matco Investments Ltd. and Matco Investments Ltd. is controlled by Ronald Mathison. To the knowledge of the Company, the only entities with an interest of greater than 10% in Matco Capital Ltd. are Matco Investments Ltd. and Mountain Moon Capital Inc. To the knowledge of the Company, the only shareholder holding, directly or indirectly, greater than 10% of the outstanding shares of Matco Investments Ltd. is Ronald Mathison and the only shareholders holding, directly or indirectly, greater than 10% of Mountain Moon Capital Inc. are members of Martin Lambert’s immediate family.

(2)		In addition to his beneficial ownership of Common Shares resulting from his control of Matco Investments Ltd., Mr. Mathison beneficially owns 13,900 Common Shares as a result of shared power to dispose of such shares.

(3)		Legal and beneficial ownership.

(a)		a Canadian resident director who is unable to be present approves in writing or by telephone or other communications facilities the business transacted at the meeting; and

(b)		the number of Canadian resident directors present at the meeting, together with any Canadian resident director who gives his approval under clause (a), totals at least half of the directors present at the meeting.

a)		each director;

b)		the auditor of the Company; and

c)		every shareholder entered in the securities registrar as the holder of a share or shares carrying the right to vote at such meetings on the record date or, if no record date was established by the directors, on the date of mailing such notice.


		HAWKER RESOURCES INC.

		By:		/s/ David A. Tuer
				Chief Executive Officer

1.		Compared the figures in the columns captioned “Hawker Resources Inc.” to the unaudited consolidated financial statements of the Company as at September 30, 2003 and for the nine months then ended, and the audited financial statements of the Company for the year ended December 31, 2002, respectively, and found them to be in agreement.

2.		Compared the figures in the columns captioned “Pointwest Energy Inc.” (“Pointwest”) to the unaudited consolidated financial statements of Pointwest as at September 30, 2003 and for the nine months then ended and the audited consolidated financial statements of Pointwest for the year ended December 31, 2002, respectively, and found them to be in agreement.

3.		Compared the figures in the columns captioned “W4M Properties Acquired” to the unaudited statement of revenues and operating expenses for the six months ended June 30, 2003 and the audited statement of revenues and operating expenses for the year ended December 31, 2002, respectively, and found them to be in agreement.

4.		Made enquiries of certain officials of the Company who have responsibility for financial and accounting matters about:

	(a)		the basis for determination of the pro forma adjustments; and

	(b)		whether the pro forma consolidated financial statements comply as to form in all material respects with applicable regulatory requirements.

	(a)		described to us the basis for determination of the pro forma adjustments, and

	(b)		stated that the pro forma consolidated financial statements comply as to form in all material respects with applicable regulatory requirements.

5.		Read the notes to the unaudited pro forma consolidated financial statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

6.		Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the columns captioned “Hawker Resources Inc.”, “Pointwest Energy Inc.” and “W4M Properties Acquired” as at September 30, 2003 and for the nine months then ended, and for the year ended December 31, 2002, and found the amounts in the column captioned “Pro forma” to be arithmetically correct.

(a)		the operating revenues and expenses for the period January 1, 2003 to June 30, 2003 and for the year ended December 31, 2002 of the 50% interest in certain oil and gas properties west of the fourth meridian (“W4M Properties”) acquired by Hawker on June 30, 2003 from Southward;

(b)		the proposed acquisition of Pointwest accounted for under the purchase method of accounting for cash consideration of $74,473;

(c)		the sale and issue of flow-through common shares on December 5, 2003; and

(d)		the sale and issue of 11,200,000 common shares and application of the net proceeds thereof, and borrowings of $31,801 under bank loans in connection with the proposed acquisition of Pointwest.

(a)		the December 31, 2002 audited financial statements of Hawker;

(b)		the December 31, 2002 audited financial statements of Pointwest;

(c)		the unaudited consolidated financial statements of Hawker as at and for the nine months ended September 30, 2003;

(d)		the unaudited consolidated financial statements of Pointwest as at and for the nine months ended September 30, 2003;

(e)		the audited statement of revenues and operating expenses of the W4M properties acquired from Southward for the year ended December 31, 2002; and

(f)		the unaudited statement of revenues and operating expenses of the W4M properties acquired from Southward for the six month period ended June 30, 2003.

(d)		the net proceeds of this offering of 11,200,000 common shares by Hawker amounting to $42,452;

(e)		the proceeds of a bank loan for $21,801 with interest at 5.25% amounting to $856 for the nine month period ending September 30, 2003 and $1,193 for the year ended December 31, 2002;

(f)		the proceeds of a bridge bank loan facility for $10,000 with interest at 7.00% amounting to $524 for the nine month period ending September 30, 2003 and $700 for the year ended December 31, 2002; and

	i)		Capitalized costs

			The Company follows the full cost method of accounting for its petroleum and natural gas operations. Under this method, all costs related to the exploration for and development of petroleum and natural gas reserves are capitalized. Costs include lease acquisitions, lease rentals on non-producing properties, geological and geophysical costs, and costs of drilling both productive and non-productive wells and production equipment costs. General and administrative costs are not capitalized other than to the extent of the Company’s working interest in operated capital expenditure programs on which operator’s fees have been charged equivalent to standard industry operating agreements. Proceeds from the sale of properties are applied against capitalized costs and gains or losses are not recognized unless such sale would alter the depletion rate by more than 20%.

	ii)		Depletion and depreciation

			Depletion and depreciation of oil and gas properties, net of estimated salvage or residual value, is provided using the unit-of-production method based upon estimated gross proven petroleum and natural gas reserves as determined by independent engineers. For depletion and depreciation purposes, relative volumes of petroleum and natural gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil.

			Office equipment is depreciated on a declining balance basis over its estimated useful life at rates varying from 20% to 50%.

	iii)		Impairment test

			The Company calculates a ceiling test whereby the carrying value of its property and equipment, net of recorded future income taxes and the accumulated provision for future site restoration and abandonment costs, is compared each reporting period-end to an estimate of future net cash flow from the production of gross proven reserves plus the lower of cost or market of unevaluated land and seismic. Net cash flow is estimated using period-end prices, less estimated future general and administrative expenses, financing costs, estimated future site restoration and abandonment costs and income taxes. Should this comparison indicate an excess carrying value, the excess is charged against operations in the period as additional depletion and depreciation.

b)		Site restoration and abandonment costs

		The estimated cost of site restoration and abandonments is based on the current cost and the anticipated method and extent of site restoration in accordance with existing legislation and industry practice. Estimated future site restoration and abandonment costs are accrued on the unit-of-production basis based on gross proven reserves. The provision is recorded on the statement of operations. Future site restoration and abandonment expenditures are charged to the accumulated provision as incurred.

c)		Use of estimates

		The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The amounts recorded for depletion and depreciation of property and equipment and the provision for site restoration and abandonment and the ceiling test are based on estimates of gross proven reserves, production rates, oil and gas prices, future costs and other relevant assumptions. These estimates are reviewed regularly and changes in such estimates in future years could be significant. As adjustments become necessary, they are reported in earnings in the periods in which they become known.

d)		Joint operations

		Substantially all of the exploration and production activities of the Company are conducted jointly with others. These consolidated financial statements reflect only the Company’s proportionate interest in such activities.

e)		Flow-through shares

		The Company finances a portion of its exploration and development activities through the issue of flow-through shares. Under the terms of the flow-through share issues, the tax deduction of the related expenditures are renounced to subscribers. For accounting purposes, a future tax liability is recognized and share capital is reduced when the shares are issued.

f)		Future income taxes

		The Company follows the liability method of accounting for income taxes. Under this method future tax assets and liabilities are determined based on differences between financial reporting and income tax bases of assets and liabilities, and are measured using substantively enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on future tax assets and liabilities of a change in tax rates is recognized in net income in the period in which the change is substantively enacted.

g)		Stock-based compensation plan

		The Company has a stock based compensation plan, which is described in note 7. No compensation expense is recorded for this plan when stock options are issued to employees and directors. Any consideration paid on the exercise of stock options is credited to share capital.

h)		Revenue recognition

		Revenues from the sale of petroleum and natural gas are recorded when title passes to an external party.

3.		Acquisition

7.		Share capital

a)		Authorized

		Unlimited number of Class A voting shares

b)		Issued

c)		Private placement

		Under the terms of a private placement in December 2000, participants subscribed for units of the Company. Subscriptions for less than 50,000 units received one common share per unit. Participants subscribing for 50,000 units or greater received 0.1 common shares, 0.6 Class A Call Obligation and 0.3 Class B Obligation. Each Class A and Class B Obligation required the holder to subscribe for 1 common share at a price of $5.00 on or before June 30, 2002. During 2001, obligations called and paid resulted in the issue of 2,499,600 class A common shares for proceeds of $12,498,000. During 2002, the balance of obligations were called and paid resulting in the issue of 1,249,800 class A common shares for proceeds of $6,249,000.

d)		Flow-through shares

		In December 2001, 279,000 flow-through Class A shares were issued at $5.00 per share for gross proceeds of $1,395,000. At December 31, 2001 the tax deductions related to these proceeds were renounced to the investors and the Company had met its obligations of these expenditures. Of the 279,000 flow through shares issued during 2001, 264,000 were issued to directors.

e)		Stock options

		The Company has a stock option plan, administered by the board of directors, in which up to 791,610 shares are reserved for issuance. Under the plan, the options that have been granted vest one-third per year and expire five years from date of issuance.

7.		Share capital (continued)

		Shares have been reserved for the following stock options outstanding:

9.		Financial instruments

a)		Fair values of financial assets and liabilities

		Financial instruments consist of cash and cash equivalents, accounts receivable, deposits, accounts payable and accrued liabilities and the demand credit facility. At September 30, 2003 and December 31, 2002 and 2001 there are no significant differences between the carrying amounts reported on the balance sheet and estimated fair values. At September 2003 and December 31, 2002 and 2001, the Company had no outstanding hedging contracts.

b)		Credit risk

		The majority of the accounts receivable are in respect of oil and natural gas operations. The Company generally extends unsecured credit to these customers, and therefore, the collection of accounts receivables may be affected by changes in economic or other conditions. Management believes the risk is mitigated by the size and reputation of the companies to which they extend credit. The Company has not experienced any material credit loss in the collection of receivables to date.

c)		Interest rate risk

		The Company is exposed to a floating rate of interest on its bank borrowings.

10.		Supplemental cash flow information

a)		Change in non-cash working capital

1.		NATURE OF OPERATIONS

		Prior to 2002, SYNSORB Biotech Inc. (“SYNSORB”) conducted pharmaceutical drug research and development. On December 10, 2001 SYNSORB terminated its drug development activities. At the Annual and Special Meeting of SYNSORB shareholders held April 3, 2003, shareholders approved the planned conversion of the company into an oil and gas enterprise and changed the company’s name to Hawker Resources Inc.

2.		SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

		The financial statements of Hawker Resources Inc. (the “Company” or “Hawker”) have been prepared in accordance with Canadian generally accepted accounting principles. These are different in some respects from those generally accepted in the United States. The significant differences are described in note 18 “Reconciliation of Canadian and United States Generally Accepted Accounting Principles”. The timely preparation of financial statements requires that management makes estimates and assumptions, and use judgement regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts. In the opinion of management, these financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

(a)		Capital Assets

		Cost

		The Company follows the full cost method of accounting whereby all costs relating to the acquisition of, exploration for and development of oil and gas reserves are capitalized in a single Canadian cost center. Such costs include lease acquisition, lease rentals on undeveloped properties, geological and geophysical, drilling both productive and non-productive wells, production equipment and overhead charges directly related to acquisition, exploration and development activities.

		Gains or losses are not recognized upon the disposition of oil and gas properties unless such a disposition would change the depletion rate by 20 percent or more. Gains and losses are recognized upon the disposition of other assets.

		Other capital assets are recorded at cost.

		Depletion, depreciation and amortization

		All costs of acquisition, exploration and development of oil and gas reserves, associated tangible plant and equipment costs (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 gross proven reserves as determined by independent engineers.

		Costs of unproved properties and seismic costs on undeveloped land are initially excluded from oil and gas properties for the purpose of calculating depletion. When proven reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.

		The relative volumes of oil and natural gas reserves and production are converted to equivalent barrels of oil based on the relative energy content of each product on a 6 to 1 basis.

		Depreciation of capital assets not related to oil and gas properties is provided using the declining balance method at rates between 20 and 30%. Leasehold improvements are amortized on a straight-line basis over the term of the lease.

		Impairment

		The Company applies a ceiling test to the capitalized costs of its oil and gas properties, net of future income taxes and asset retirement obligations, to ensure that the net carrying value does not exceed the estimated value of future net revenues from production of gross proven reserves plus undeveloped properties less future production-related general and administrative expenses, financing costs, site restoration and abandonment costs and income taxes. Any reduction in the net carrying value of oil and gas properties as a result of the ceiling test is charged to operations.

		The calculation of future net revenues is based on sales prices, costs and regulations in effect at period end.

		The carrying value of undeveloped properties (land and seismic data) is reviewed periodically and written down to net realizable value if impairment is determined.

(b)		Asset Retirement Obligations

		The Company recognizes the fair value of a liability for an asset retirement obligation in the period in which it is incurred and records a corresponding increase in the carrying value of the related long-lived asset. The fair value is determined through a review of engineering studies, industry guidelines, and management’s estimate on a site by site basis. The liability is subsequently adjusted for the passage of time, and is recognized as an accretion expense in the statement of earnings under asset retirement obligations. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. The increase in the carrying value of the asset is amortized using the unit of production method based on estimated gross proven reserves as determined by independent engineers.

(c)		Leasehold Inducements

		Leasehold inducements are accounted for as a reduction of rental expense over the term of the related lease.

(d)		Revenue Recognition

		Oil and natural gas sales are recognized as revenue when the commodities are delivered to purchasers.

		Revenue from milestone payments and royalties is recognized when received.

(e)		Hedging and Forward Sales Contracts

		In certain circumstances, fixed price commodity contracts or commodity derivative contracts are used to reduce the Company’s exposure to adverse fluctuations in commodity prices to protect future cash flow used to finance the Company’s capital expenditure program. Gains and losses relating to commodity derivative contracts which settle via net cash payment and that meet hedge criteria are recognized as part of natural gas sales concurrently with the hedged transaction. The Company does not enter into financial instruments for trading or speculative purposes.

		The Company believes the derivative financial instruments are effective as hedges, both at inception and over the term of the instrument, as the term to maturity, the notional amount and the commodity price basis in the instruments all match the terms of the future revenue stream being hedged.

		Realized and unrealized gains and losses associated with commodity derivative contracts which have been terminated or cease to be effective prior to maturity, are deferred as other current, or non-current, assets or liabilities on the balance sheet, as appropriate, and recognized in earnings in the period in which the underlying hedged transaction is recognized. In the event a designated hedged item is sold, extinguished or matures prior to the termination of the related derivative instrument, any realized or unrealized gain or loss on such derivative instrument is recognized in earnings.

(f)		Joint Ventures

		Substantially all of the Company’s exploration, development and production activities are conducted jointly with others and, accordingly, these financial statements reflect only the Company’s proportionate interest in such activities.

(g)		Stock Based Compensation

		Under the Company’s stock option plan, options to purchase common shares are granted to directors, officers, employees and consultants at current market prices. Options issued by the Company in 2003 are accounted for in accordance with the fair value method of accounting for stock-based compensation, and as such the cost of the option is charged to earnings with an offsetting amount recorded to contributed surplus, based on an estimate of the fair value determined using a Black-Scholes options pricing model. No compensation expense has been recorded on options issued in 2002 or 2001(see note 10).

(h)		Investments

		Investments in marketable securities are recorded at the lower of cost and market value. At December 31, 2003, the investments had a quoted market value of $3,012,000.

		The Company used the equity method of accounting for its investment in Oncolytics Biotech Inc. (“Oncolytics”) up until the end of the first quarter of 2002 when it no longer exerted significant influence over Oncolytics. Under this method of accounting, the Company included in its net earnings its share of the net earnings or losses of Oncolytics. Subsequent to this date, the investment was accounted for on a cost basis and accordingly, no net earnings or losses of Oncolytics have been included in net earnings subsequent to March 31, 2002 (see note 4(d)).

(i)		Future Income Taxes

		The Company follows the liability method of accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse. Income tax expense for the period is the tax payable for the period and any change during the period in future income tax assets and liabilities. A valuation allowance is recorded to the extent that there is uncertainty regarding utilization of future tax assets.

(j)		Per Common Share Amounts

		The Company uses the treasury stock method to determine the dilutive effect of stock options. This method assumes that proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the year.

(k)		Measurement Uncertainty

		The amount recorded for depletion and depreciation of petroleum and natural gas properties, the provision for asset retirement obligation costs and the ceiling test calculation are based on estimates of gross proven reserves, production rates, commodity prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be significant.

(l)		Flow-through Common Shares

		Resource expenditure deductions for income tax purposes related to exploration and development activities funded by flow-through share arrangements are renounced to investors in accordance with income tax legislation. The estimated tax benefits transferred to shareholders are recorded as future income taxes and a reduction to share capital when the expenditures are renounced.