Exhibit 15

EXCERPTS FROM PROSPECTUS

DATED DECEMBER 19, 2003
RELATING TO THE OFFERING OF $45,360,000 OF HAWKER SHARES

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RECENT DEVELOPMENTS

Proposed Acquisition of Pointwest Energy Inc.

On December 9, 2003, Hawker entered into an acquisition agreement (the “Acquisition Agreement”) with Pointwest providing for the acquisition by Hawker of all of the issued and outstanding Pointwest common shares for an aggregate cost of approximately $88 million, including Pointwest net debt of approximately $14 million, transaction costs of approximately $1 million and approximately $6 million payable by Pointwest for cancellation of outstanding options to acquire Pointwest common shares.

Pointwest’s average production for the nine months ended September 30, 2003 was approximately 3,355 boe/d, and was 89% weighted to natural gas. See “Information Concerning the Pointwest Properties – Selected Historical Quarterly Information – Production History”. The asset base is highly concentrated in the Boundary Lake North area of British Columbia, just west of the Alberta border. Approximately 90% of the production from the Pointwest properties is operated by Pointwest, with Pointwest having approximately an 80% working interest in such production.

The acquisition of Pointwest will be effected by the Corporation making an offer to all Pointwest shareholders (the “Offer”), on an exempt take-over bid basis, to acquire all Pointwest common shares (including any common shares of Pointwest issued on the exercise of presently outstanding options) at a purchase price of $12.71 cash per Pointwest common share.

The Acquisition Agreement provides that all holders of outstanding options under Pointwest’s stock option plan may exercise their options and tender to the Offer the Pointwest common shares issued upon such exercise. Alternatively, in lieu of exercising options, holders of options are entitled to receive from Pointwest a cash payment equal to the difference between the exercise price of any such option and the Offer price of $12.71 in exchange for cancellation of such options (the “cashless exercise option”). The aggregate amount payable by Pointwest pursuant to the cashless exercise option for all outstanding options is approximately $6 million.

The closing of the Offering is conditional upon the concurrent closing of the acquisition of Pointwest, both of which are anticipated to occur on or about December 30, 2003, but, in any event, not later than January 29, 2004.

Hawker’s obligation to complete the Offer is conditional upon, among other things, the tendering to the Offer of at least 90% of the Pointwest common shares (on a fully-diluted basis) (the “Minimum Condition”). The Acquisition Agreement is also subject to the completion of the Offering and the satisfaction of certain industry standard terms and conditions. The Acquisition Agreement obligates the Corporation to use its reasonable commercial efforts to consummate the Offer, including the completion of the Offering.

Concurrent with execution of the Acquisition Agreement, the directors, officers and certain shareholders of Pointwest executed pre-tender agreements (“Pre-Tender Agreements”) whereby such persons agreed to, among other things, irrevocably deposit all of their Pointwest common shares to the Offer. Pursuant to the Pre-Tender Agreements, each director, officer or shareholder party thereto agreed not to exercise any options held by them to acquire Pointwest common shares and instead to utilize the cashless exercise option except for two individuals who have indicated to management of the Corporation that they intend to exercise their options and tender to the Offer the Pointwest common shares received upon such exercise.

The Pre-Tender Agreements received by Hawker encompass approximately 92% of the basic outstanding Pointwest common shares, assuming the exercise of the options held by the two individuals described above. The Pre-Tender Agreements terminate only in the event that: (i) Hawker fails to make the Offer by December 15, 2003; (ii) Hawker does not take up and pay for the Pointwest common shares on or before January 9, 2004; (iii) the Corporation waives the Minimum Condition, decreases the consideration offered pursuant to the Offer or otherwise modifies or amends the Offer in a manner materially adverse to the holders of Pointwest common shares; or (iv) the Acquisition Agreement is terminated pursuant to certain of its terms.

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The Acquisition Agreement can only be terminated in certain limited circumstances, including by Pointwest:

(a)	if the Corporation has not mailed the Offer to Pointwest shareholders on or before midnight (Calgary time) on December 15, 2003;
(b)	if the Corporation has not taken up and paid for the Pointwest common shares deposited to the Offer within 30 days following mailing of the Offer to Pointwest shareholders;
(c)	if the Offer expires without the Corporation taking up and paying for any Pointwest common shares as a result of a condition to the Offer not being satisfied or waived unless such circumstance is due to the failure of Pointwest to perform its obligations under the Acquisition Agreement; and
(d)	if there has been a misrepresentation, breach or non-performance by the Corporation of any representation, warranty or covenant in the Acquisition Agreement which would reasonably be expected to have a material adverse effect on Pointwest, subject to notice to the Corporation and a cure period.

Management of Hawker believes that the acquisition of Pointwest will provide benefits to the combined entity, including:

(a)	a stronger entity with a larger production, reserve and undeveloped land base and the financial capacity to compete more effectively in the oil and natural gas industry in western Canada;
(b)	enhanced exploitation opportunities through further development of Pointwest’s undeveloped land base in the core areas where the Corporation has experienced exploration success;
(c)	increased opportunities for working interest consolidations and property swaps resulting from the larger property base of the consolidated entity; and
(d)	increased control over operations due to the proportion of the asset base that will be operated by Hawker.

Upon the completion of the acquisition of Pointwest, Hawker will have initial production on a combined basis of approximately 37 mmcf/d of natural gas and NGLs and 180 bbls/d of crude oil.

For further discussion and analysis of the effect on the Corporation of acquiring Pointwest see “Consolidated Capitalization of the Corporation” and the unaudited pro forma consolidated financial statements of the Corporation and notes thereto set forth in this short form prospectus.

INFORMATION CONCERNING THE POINTWEST PROPERTIES

Oil and Natural Gas Reserves

Gilbert Laustsen Jung Associates Ltd. (“GLJ”), independent oil and natural gas reservoir engineers of Calgary, Alberta, has prepared a report (the “GLJ Report”) in which it evaluated the oil, natural gas and NGL reserves of Pointwest, effective September 30, 2003. GLJ conducted evaluations based on both escalated and constant price assumptions of Pointwest’s oil, natural gas and NGL reserves and the present worth of estimated future cash flows associated with such reserves. The results of the evaluation of GLJ, contained in the GLJ Report, based on both escalated and constant price assumptions, are summarized in the tables below. The present worth of estimated future cash flows contained in the following tables may not be representative of the fair market value of the reserves. Assumptions relating to costs, prices for future production and other matters are summarized in the notes following the tables. There is no assurance that such process and cost assumptions will be attained and variances could be material. All estimated future cash flows as set forth in the following tables are stated prior to provision for income taxes, indirect costs, and future site restoration costs, and after deduction of operating costs, royalties and estimated future capital expenditures.

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Pointwest Properties
Petroleum and Natural Gas Reserves and Pre-Tax Estimated Net Present Worth
Escalating Prices and Costs

	Gross Reserves						Net Reserves						Pre-Tax Estimated Net Present Worth
													(thousands of dollars)
					Natural						Natural
			Natural		Gas				Natural		Gas		Discounted at
	Oil		Gas		Liquids		Oil		Gas		Liquids
	(mbbls)		(bcf)		(mbbls)		(mbbls)		(bcf)		(mbbls)		0%		10%		15%		20%
Proved Producing		126		17.8		220		111		14.1		171		69,913		49,681		44,485		40,613
Proved Non- Producing		120		9.7		120		100		7.3		91		27,796		20,461		18,038		16,118
Total Proved		246		27.5		340		211		21.4		262		97,709		70,142		62,523		56,731
Risked Probable		39		3.3		38		34		2.6		30		12,751		6,265		4,984		4,126
Established Reserves		285		30.8		378		245		24.0		292		110,460		76,407		67,507		60,857

Pointwest Properties
Petroleum and Natural Gas Reserves and Pre-Tax Estimated Net Present Worth
Constant Prices and Costs

	Gross Reserves						Net Reserves						Pre-Tax Estimated Net Present Worth
													(thousands of dollars)
					Natural						Natural
			Natural		Gas				Natural		Gas		Discounted at
	Oil		Gas		Liquids		Oil		Gas		Liquids
	(mbbls)		(bcf)		(mbbls)		(mbbls)		(bcf)		(mbbls)		0%		10%		15%		20%
Proved Producing		127		17.8		219		111		14.1		171		76,990		54,689		48,699		44,206
Proved Non- Producing		124		9.7		120		103		7.2		91		32,403		23,587		20,689		18,396
Total Proved		251		27.5		33.9		214		21.3		262		109,393		78,276		69,388		62,602
Risked Probable		38		3.3		39		32		2.7		30		13,854		71,118		5,673		4,693
Established Reserves		289		30.8		378		246		24.0		292		123,247		85,394		75,061		67,295

Notes to Reserve Determinations

The following notes provide important information relating to the preceding reserve determinations.

(1)	“Gross” reserves are defined as Pointwest’s working, lessor royalty, and overriding royalty interest share of the remaining reserves, before deduction of any royalties.
(2)	“Net” reserves are defined as the Gross remaining reserves of the properties in which Pointwest has an interest, less all crown, freehold, and overriding royalties and interests owned by others.
(3)	Definitions used for reserve categories in the GLJ Report are as follows:

“Proved Reserves”: Those reserves estimated as recoverable under current technology and existing economic conditions in the case of constant price and cost analyses and anticipated economic conditions in the case of escalated price and cost analyses, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by

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enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir.

“Probable Reserves”: Those reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved, but where such analysis suggests the likelihood of their existence and future recovery under current technology and existing or anticipated economic conditions. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above that estimated in the proved category which can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future.

Development and Production Status

GLJ has divided the proved and probable reserves into producing and nonproducing categories and has further subdivided proved nonproducing reserves into developed nonproducing and undeveloped subcategories, in accordance with the following criteria:

“Producing Reserves”: Those reserves that are actually on production or, if not producing, that could be recovered from existing wells and facilities and where the reasons for the current nonproducing status is the choice of the owner rather than the lack of markets or some other reasons. An illustration of such a situation is a well or zone which is capable but is shut-in because its deliverability is not required to meet contract commitments. If reserves are currently shut-in, the date of resumption of production must be known with reasonable certainty.

“Nonproducing Reserves”: Those reserves that are not currently producing either due to lack of facilities and/or markets. The nonproducing category may be subdivided into developed and undeveloped (GLJ presents these subcategories only for proved reserves):

Developed Nonproducing Reserves

Nonproducing 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 (e.g. when compared to the cost of drilling a well) to put the reserves on production.

Undeveloped Reserves

Those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. 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.

In multi-well pools it may be appropriate to allocate total pool reserves between the producing and nonproducing categories, or to subdivide the reserves for the pool between developed and undeveloped. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Evaluated Reserves Categories

Production/revenue projections are prepared on an unrisked basis for each of the following main reserves categories:

Proved Producing
Proved Developed Nonproducing
Proved Undeveloped
Total Proved
Proved Plus Probable Producing
Total Proved Plus Probable

Where “Total Proved” and “Total Proved Plus Probable” represent the sum of the producing, developed nonproducing and undeveloped reserves. Other reserves categories are presented within this summary report for analysis convenience and are determined by difference. GLJ evaluates the possible reserves component only when specifically requested to do so.

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When evaluating reserves, GLJ evaluators generally first identify the producing situation and assign proved and proved plus probable reserves in recognition of the existing level of development and the existing depletion strategy. Incremental nonproducing (developed nonproducing or undeveloped) reserves are subsequently assigned recognizing future development opportunities and enhancements to the depletion mechanism. It should be recognized that future developments may result in accelerated recovery of producing reserves.

(4)

The price forecasts that formed the basis for the revenue projections in the GLJ Report were based on GLJ’s October 1, 2003 price model. The oil, natural gas and NGL escalating prices used in the GLJ Report are as follows:

										Alberta Natural Gas Liquids
				Edmonton		Alberta
		WTI Cushing		Par Price(1)		Plantgate		Alberta 30		Edmonton		Edmonton		Edmonton
		Oklahoma		40° API		Index		Day spot		Propane		Butane		Pentanes Plus
Year		(USS/bbl)		($/bbl)		($/mmbtu)		AECO ($/mcf)		$Cdn/bbl		$Cdn/bbl		$Cdn/bbl
2003 Q4			28.25		38.00		5.50		5.75		26.00		29.00		38.50
	2004		25.00		34.00		5.80		6.05		21.25		23.00		34.50
	2005		23.00		32.00		4.70		4.95		20.00		22.00		32.50
	2006		23.00		32.00		4.70		4.95		20.00		22.00		32.50
	2007		23.00		32.00		4.70		4.95		20.00		22.00		32.50
	2008		23.00		32.00		4.75		5.00		20.00		22.00		32.50
	2009		23.00		32.00		4.85		5.10		20.00		22.00		32.50
	2010		23.25		32.50		4.95		5.20		20.50		22.50		33.00
	2011		23.75		33.00		5.05		5.30		23.00		23.00		33.50
	2012		24.00		33.50		5.15		5.35		23.50		23.50		34.00
	2013		24.50		34.00		5.20		5.45		21.75		24.00		34.50
	2014+	+1.5%/yr		+1.5%/yr		+1.5%/yr		+1.5%/yr		+1.5%/yr		+1.5%/yr		+1.5%/yr

Note:

                    (1) 40 degrees API, 0.3% sulphur.

The oil, natural gas and NGL constant prices used in the GLJ Report are based on the following constant prices:

Wellhead Prices:

Natural gas	$5.51/mcf
Crude oil	$35.42/bbl
Natural gas liquids	$32.36/bbl

(5)	In the course of the evaluation, Pointwest provided GLJ personnel with basic information which included land data, well information, geological information, contract information, operating cost data, financial data and discussions of future operating plans. Other engineering, geological or economic data required to conduct the evaluation and upon which the GLJ Report is based, was obtained from public records, other operators, and from GLJ nonconfidential files. The extent and character of ownership and accuracy of all factual data supplied for the independent evaluation, from all sources, has been accepted as represented. The accuracy of any reserves or production estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserves and production estimates presented herein are considered reasonable, the estimates should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. Revenue projections presented in the GLJ Report are based in part on forecasts of market prices, currency exchange rates, inflation, market demand and government policy which are subject to many uncertainties and may, in future, differ materially from the forecasts utilized in the GLJ Report. Present values of revenues documented in the GLJ Report do not necessarily represent the fair market value of the reserves evaluated therein.
(6)	Columns may not add due to rounding.
(7)	The GLJ Report includes certain capital expenditures over 2003, 2004 and 2005 in order to achieve the predicted present worth values in the escalated price and constant price cases. Total capital expenditures (net to Pointwest total proved reserves) of $2,682,000 and $7,090,000 are to be expended in 2003 and 2004, respectively, in the escalated price case and $2,682,000 and $6,985,000 are to be expended in 2003 and 2004, respectively, in the constant price case. Total capital expenditures (net to Pointwest total proved

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reserves) required during the remaining life of the Pointwest properties are $84,000 in the constant price case.

Principal Producing Properties

The following is a description of Pointwest’s principal properties on production or under development as at September 30, 2003. The term “net”, when used to describe Pointwest’s share of production, means the total of Pointwest’s working interest share before deduction of royalties owned by others.

Boundary Lake North

The Boundary Lake North assets are located near Fort St. John, British Columbia, just west of the Alberta border, and are comprised of a significant contiguous group of properties with high working interests. Pointwest has an average 84% working interest in 39,818 gross acres (33,414 net acres) of land in the Boundary Lake North area. Production is approximately 3,043 boe/d, comprised of approximately 17,500 mcf/d of natural gas and approximately 121 bbls/d of oil and NGLs. The Boundary Lake North properties offer year-round access.

The Boundary Lake North area is characterized by multi-target zones for both natural gas and oil, including the Gething, Baldonnel, Boundary, Coplin, Halfway and Doig formations. Pointwest operates the wells in the area, as well as the associated pipelines, compression and dehydration facility.

The GLJ Report assigns 22,535 mmcf of proved natural gas reserves and 371 mbbls of proved crude oil and NGLs reserves to the Boundary Lake North property. In addition, 2,341 mmcf of risked probable natural gas reserves and 44 mbbls of risked probable crude oil and NGLs reserves have been assigned to this property. The GLJ Report is an evaluation of Pointwest’s oil, natural gas and NGL reserves as at September 30, 2003. Hawker believes that drilling activities on the Pointwest properties in the fourth quarter of 2003 indicate that significant reserve additions and, upon tie-in, increased production volumes are possible.

Valhalla

The Valhalla acreage is situated 60 kilometers northwest of Grande Prairie, Alberta. Pointwest has a 100% working interest in 1,940 gross acres in the area, and holds a rolling option farm-in on an additional 4,160 gross acres in the area. Production is approximately 297 boe/d, comprised of approximately 1,500 mcf/d of natural gas and approximately 47 bbls/d of oil and NGLs. Like the Boundary Lake North assets, the Valhalla assets allow for year-round access.

Petroleum and natural gas rights held vary on the acreage, but are generally to the base of the Montney formation. Production is being derived from the Montney, Gething and Doe Creek formations. The Valhalla acreage is centrally located on the Peace River Arch, an area which often offers stacked multi-target reservoirs with hydrocarbon migration and reservoir distribution influenced by faulting.

Land Summary

Pointwest has an interest in approximately 88,082 acres of land (52,489 net acres) in western Canada. Of the net acreage, approximately 61% is undeveloped (40,827 gross acres and 32,073 net acres). The following table summarizes the developed and undeveloped land included in Pointwest’s properties, as at October, 2003.

						Average
						Working
Property		Gross Acres(1)		Net Acres(2)		Interest
Boundary Lake North
	Developed land		16,771		12,075		72	%
	Undeveloped land		23,047		21,339		93	%
	Total		39,818		33,414		84	%

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						Average
						Working
Property		Gross Acres(1)		Net Acres(2)		Interest
Valhalla
	Developed land		1,300		1,300		100	%
	Undeveloped land		640		640		100	%
	Total		1,940		1,940		100	%
Other Areas
	Developed land		32,867		9,714		30	%
	Undeveloped land		13,457		7,421		55	%
	Total		46,324		17,135		37	%
Total
	Developed land		50,938		23,089		45	%
	Undeveloped land		37,144		29,400		79	%
	Total		88,082		52,489		60	%

Notes:

(1)	“Gross Acres” means the total acres in which Pointwest holds an interest.
(2)	“Net Acres” means the total acres in which Pointwest holds an interest, multiplied by the working interest therein.

Oil and Natural Gas Wells

The following table sets forth the producing wells and wells capable of producing included in the Pointwest properties as at September 30, 2003.

	Oil Wells								Natural Gas Wells
	Producing				Shut-in(3)				Producing				Shut-in(3)
	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Boundary Lake North		1.00		0.375		—		—		17.00		13.89		6.00		5.35
Valhalla		1.00		0.60		—		—		2.00		2.00		2.00		1.09
Other Areas		1.00		0.11		—		—		41.00		17.15		20.00		4.78
Total		3.00		1.09		—		—		60.00		33.04		28.00		11.22

Notes:

(1)	“Gross Wells” means all wells in which Pointwest has a working interest.
(2)	“Net Wells” means the total wells in which Pointwest has a working interest, multiplied by the working interest therein.
(3)	“Shut-in Wells” are wells which are capable of economic production or which Pointwest 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.

Drilling History

The following table sets forth the number of gross and net exploratory and development wells comprised in the Pointwest properties which were completed, capped or abandoned during the periods indicated.

	Nine Months Ended
	September 30				Years Ended December 31
	2003				2002				2001
	Gross Wells(1)		Net Wells(2)		Gross Wells(1)		Net Wells(2)		Gross Wells(1)		Net Wells(2)
Exploratory
Gas		4.0		3.6		4.0		3.8		1.0		0.8
Oil		—		—		—		—		—		—
Dry(3)		—		—		1.0		1.0		2.0		2.0
Total Exploratory		4.0		3.6		5.0		4.8		3.0		2.8
Development
Gas		5.0		4.6		6.0		5.5		4.0		3.6
Oil		—		—		2.0		1.5		3.0		2.6

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	Nine Months Ended
	September 30				Years Ended December 31
	2003				2002				2001
	Gross Wells(1)		Net Wells(2)		Gross Wells(1)		Net Wells(2)		Gross Wells(1)		Net Wells(2)
Dry(3)		—		—		—		—		—		—
Total Development		5.0		4.6		8.0		7.0		7.0		6.2
Total Drilling Activity		9.0		8.2		13.0		11.8		10.0		9.0

Notes:

(1)	“Gross Wells” means the total wells in which Pointwest has an interest.
(2)	“Net Wells” means the total wells in which Pointwest has an interest, multiplied by the working interest therein.
(3)	“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 natural 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.

Reconciliation of Reserves

The following table summarizes the changes to the proved reserves (before royalties) in the Pointwest properties from December 31, 2001 to September 30, 2003.

	Oil and NGLs (mbbls)									Natural Gas (mmcf)
	Proved			Probable			Total			Proved			Probable		Total
December 31, 2001		284			202			486			4,307			1,716		6,023
Production		(106	)		—			(106	)		(3,522	)		—		(3,522	)
Acquisitions		—			—			—			—			—		—
Additions		447			(34	)		413			18,853			2,428		21,281
Dispositions		—			—			—			—			—		—
December 31, 2002		625			168			793			19,638			4,144		23,782
Production		(103	)		—			(103	)		(4,840	)		—		(4,840	)
Acquisitions		8			—			8			552			34		586
Additions		56			(13	)		43			12,123			2,432		14,555
Dispositions		—			—			—			—			—		—
September 30, 2003		586			155			741			27,473			6,610		34,083

Selected Historical Quarterly Information

Production History

The following table shows the average daily production volumes from the Pointwest properties, before the deduction of royalties, for each of the fiscal quarters of 2001 and 2002.

	2002								2001
	Three Months		Three Months		Three Months		Three Months		Three Months		Three Months		Three Months		Three Months
	Ended		Ended		Ended		Ended		Ended		Ended		Ended		Ended
	March 31		June 30		September 30		December 31		March 31		June 30		September 30		December 31
Natural Gas (mcf/d)		1,772		4,507		14,036		18,059		—		323		1,007		1,432
Crude Oil & NGLs (bbls/d)		181		200		282		495		—		6		26		27
boe/d		476		951		2,621		3,505		—		60		194		266

The following table shows the average daily production volumes from the Pointwest properties, before the deduction of royalties, for each of the first three fiscal quarters of 2003.

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	2003
	Three Months		Three Months		Three Months
	Ended		Ended		Ended
	March 31		June 30		September 30
Natural Gas (mcf/d)		20,951		16,892		15,410
Crude Oil & NGLs(bbls/d)		468		395		276
boe/d		3,960		3,210		2,844

The production rates of Pointwest vary over time and as between periods due to several factors. The oil and gas reservoirs in which Pointwest holds interests are generally characterized by favourable initial rates of production from successful wells, followed by rapid initial decline rates, until a more stable production rate is reached. In an active drilling program, as undertaken by Pointwest historically and as planned by Hawker in the future, corporate production rates tend to rise as each new well comes onstream and then begin to decline. Accordingly, rates will vary over time. Hawker’s focus is on the overall well economics, being the aggregate return anticipated over the life of each well relative to its capital, operating and other costs. Hawker believes these economics to be very favourable for both its existing properties and the Pointwest properties.

Netback ($ per boe)

The following table summarizes the average netbacks received for the production from the Pointwest properties for each of the fiscal quarters of 2001 and 2002.

	2002								2001
			Three								Three
	Three Months		Months		Three Months		Three Months		Three Months		Months		Three Months		Three Months
	Ended		Ended		Ended		Ended		Ended		Ended		Ended		Ended
	March 31		June 30		September 30		December 31		March 31		June 30		September 30		December 31
Sales Price	$	25.64	$	26.24	$	21.50	$	36.27		—	$	27.06	$	23.53	$	22.65
Royalties		4.39		5.24		4.82		8.98		—		3.66		3.41		2.82
Operating Costs		5.53		5.21		5.22		4.62		—		6.77		8.76		11.86
Netback		15.72		15.79		11.46		22.67		—		16.63		11.36		7.97

The following table summarizes the average netbacks received for the production from the Pointwest properties for each of the first three fiscal quarters of 2003.

	2003
	Three Months		Three Months		Three Months
	Ended		Ended		Ended
	March 31		June 30		September 30
Sales Price	$	49.26	$	42.95	$	38.08
Royalties		12.53		9.16		9.82
Operating Costs		4.53		4.60		4.33
Netback		32.20		29.19		23.93

Capital Expenditures

The following table summarizes the capital expenditures in respect of the Pointwest properties in the categories indicated for each of the fiscal quarters of 2001 and 2002.

	2002								2001
	Three										Three
	Months		Three Months		Three Months		Three Months		Three Months		Months		Three Months		Three Months
	Ended		Ended		Ended		Ended		Ended		Ended		Ended		Ended
	March 31		June 30		September 30		December 31		March 31		June 30		September 30		December 31
Land acquisitions	$	203,588	$	5,592,659	$	544,685	$	1,295,726	$	369,112	$	428,609	$	130,963	$	185,027
Exploration (including drilling)		1,746,534		28,557		1,883,232		1,243,562		—		63,000		1,785,267		466,964
Development (including facilities)		4,043,1667		7,938,166		4,056,449		7,421,658		10,371		1,786,486		1,221,987		1,433,006
Total		5,993,289		13,559,382		6,484,366		9,960,946		379,483		2,278,095		3,138,217		2,084,997

10

The following table summarizes the capital expenditures in respect of the Pointwest properties in the categories indicated for each of the first three fiscal quarters of 2003.

	2003
	Three Months		Three Months		Three Months
	Ended		Ended		Ended
	March 31		June 30		September 30
Land acquisitions	$	1,156,639	$	722,537	$	16,395
Exploration (including drilling)		3,329,575		1,166,806		2,700,822
Development (including facilities)		7,405,941		1,829,784		7,020,173
Total		11,892,155		3,719,127		9,737,390

Future Commitments

Pointwest currently has no forward sales contracts or financial hedging contracts with respect to production from the Pointwest properties.

11

Auditors’ Report

To the Board of Directors of
Pointwest Energy 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 Canadian generally accepted auditing standards. 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.

/s/ KPMG LLP

Chartered Accountants

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

F-12

Pointwest Energy Inc.
Consolidated Balance Sheets

		September 30,		December 31,		December 31,
		2003		2002		2001
Assets		(unaudited)
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) Cameron McVeigh Director	(signed) Larry J. Macdonald Director

See accompanying notes

F-13

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

	Nine months ended						Years ended						Period from
	September 30						December 31						July 25 to
													December 31
	2003			2002			2002			2001			2000
	(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			2,570,692			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	)		(201,1140	)
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	)		(201,1140	)
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-14

Pointwest Energy Inc.
Consolidated Statements of Cash Flows

													Period from
	Nine months ended						Years ended						July 25 to
	September 30						December 31						December 31
	2003			2002			2002			2001			2000
	(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	)		—
Funds from (used in) operating activities		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-15

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. 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.

F-16

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

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 estimated 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.

F-17

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

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 result of the 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

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

F-18

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

the depletion calculation. Future capital expenditures in the amount of $7,894,780 (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.

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 Class A common shares

	Number 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

F-19

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

	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:

	Period ended				Year ended				Year ended
	September 30, 2003				December 31, 2002				December 31, 2001
			Weighted				Weighted				Weighted
			Average				Average				Average
			Exercise				Exercise				Exercise
			Price				Price				Price
	Shares		$		Shares		$		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:

			Weighted Average
	Number		Remaining		Number
Exercise Price	Outstanding At		Contractual Life		Exercisable At		Weighted Average
$	September 30, 2003		(years)		September 30, 2003		Exercise Price
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

F-20

Pointwest Energy Inc.
Notes to the Consolidated Financial Statements

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

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-21

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:

	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-22

AUDITORS’ REPORT

To the Directors of
Hawker Resources Inc.:

We have audited the accompanying statements of revenues and operating expenses relating to the proposed acquisition by Hawker Resources Inc. of certain petroleum and natural gas properties (the “Southward Properties”) for each of the years in the three-year period ended December 31, 2002. This financial information is the responsibility of the management of Hawker Resources Inc. Our responsibility is to express an opinion on this financial information based on our audits.

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

In our opinion, these statements present fairly, in all material respects, the revenues and operating expenses of the Southward Properties to be acquired as described in Note 1 for each of the years in the three-year period ended December 31, 2002 in accordance with Canadian generally accepted accounting principles.

Calgary, Alberta	(Signed) “Deloitte & Touche LLP”
April 21, 2003	Chartered Accountants

F-23

Hawker Resources Inc.

Southward Properties
Statements of Revenues and Operating Expenses

	Six Months			Year ended
	Ended			December 31,
	June 30,
	2003			2002			2001			2000
	(Unaudited)
REVENUES	$	21,248,479		$	24,395,200		$	35,146,368		$	22,121,330
ROYALTIES		(5,757,489	)		(6,088,471	)		(9,020,145	)		(6,118,864	)
		15,490,990			18,306,729			26,126,223			16,002,466
OPERATING EXPENSES		1,794,604			3,708,256			2,792,051			1,915,539
EXCESS OF REVENUES OVER OPERATING EXPENSES	$	13,696,386		$	14,598,473		$	23,334,172		$	14,086,927

F-24

Hawker Resources Inc.
Southward Properties
Notes to the Statement of Revenues and Operating Expenses
For the Six Months Ended June 30, 2003 (Unaudited) and for Each of the Years in the Three-Year Period Ended December 31, 2002

1.	BASIS OF PRESENTATION
	The accompanying statements of revenues and operating expenses have been prepared for inclusion in the prospectus (the “Prospectus”) of Hawker Resources Inc. (the “Company”) relating to the sale and issue of common shares by the Company.
	The Company, through its wholly-owned subsidiary, 1022971 Alberta Ltd., has entered into an arrangement agreement with Southward Energy Ltd. (“Southward”) that contemplates the acquisition of all of the outstanding common shares of Southward in an arm’s length transaction. The Company has also entered into an agreement to sell all of the petroleum and natural gas properties of Southward, with the exception of an undivided interest of 1% in certain properties (the “Optioned Properties”) which will be retained by the Company. The Optioned Properties, which are further described elsewhere in the Prospectus, are comprised of all of the petroleum and natural gas properties of Southward except for those which are located in the west of the fifth meridian area in the province of Alberta.
	The Company holds an option to acquire an undivided interest of 49% in the Optioned Properties, which upon exercise will result in the Company holding an aggregate undivided interest of 50% in the Optioned Properties (the “Southward Properties”).
	These statements have been derived from financial information provided by the vendor of the Southward Properties and relate only to 50% of the working interests in such properties, which are to be acquired by the Company. These statements include only those revenues and operating expenses which are directly related to the Southward Properties and do not include any expenses related to general and administrative costs, interest, income and capital taxes or any provisions related to depletion, depreciation or future site restoration and abandonment.
2.	SIGNIFICANT ACCOUNTING POLICIES

a.	Revenue
	Production sales are recorded when the commodities are sold. Processing income is recognized at the time services are performed.
b.	Operating Expenses
	Operating expenses include all costs related to the lifting, gathering, transporting and processing of oil and gas related products.

F-25