Dynamic Oil & Gas (DYOLF) 20-F 2004 FY Annual report (foreign)

Exhibit 14

REPORT OF

MANAGEMENT AND DIRECTORS

ON OIL AND GAS DISCLOSURE

Form 51-101

TABLE OF CONTENTS

			Pages
Glossary of Terms			2
Form 51-101F1
	Item 2.1	Reserves Data - Constant Prices and Costs	4-5
	Item 2.2	Reserves Data - Forecast Prices and Costs	5-6
	Item 2.3	Reserves Disclosure Varies with Accounting	6
	Item 2.4	Future Net Reserves Disclosure Varies with Accounting	6
	Item 3.1	Constant Prices Used in Estimates	7
	Item 3.2	Forecast Prices Used in Estimates	7
	Item 4.1	Reserves Reconciliation	8
	Item 4.2	Future Net Revenue Reconciliation	9
	Item 5.1	Undeveloped Reserves	9-10
	Item 5.2	Significant Factors and Uncertainties	10
	Item 5.3	Future Development Costs	10
	Item 6.1	Oil and Gas Properties and Wells	11-16
	Item 6.2	Undeveloped Properties Having No Attributed Reserves	17-18
	Item 6.3	Forward Contracts	18
	Item 6.4	Additional Information - Abandonment and Reclamation Costs	18
	Item 6.5	Tax Horizon	19
	Item 6.6	Costs Incurred	19
	Item 6.7	Exploration and Development Activities	19
	Item 6.8	Production Estimates	20
	Item 6.9	Production History	20-21
Form 51-101F2			22-23
Form 51-101F3			24-25

Glossary of Terms
Reserves	Estimated reserves of natural gas, natural gas liquids and crude oil.
Working interest	Those lands in which the Company receives its share acreage of net production revenues.
Gross reserves	Estimated reserves before royalties based on working interest. Net reserves Estimated reserves after royalties based on working interest
Future net revenue	Working interest revenues after royalties, development costs, production costs and well abandonment costs, but before administrative, overhead and other such indirect costs. Future net revenue may be presented either before or after tax.
NGL’s	Natural gas liquids. Hydrocarbon components recovered from raw natural gas as liquids by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butane and pentane plus, or combinations thereof.
Proved reserves	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.
Probable reserves	Reserves that are less certain than proved reserves at being recovered. 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
Developed reserves	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.
Developed producing reserves	Reserves that are expected to be recovered from completion intervals open at the time of estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
Developed non-producing reserves	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.
stb or stock tank barrel	A 42-gallon barrel of crude oil at standard conditions of temperature and pressure.
mbbl	1,000 barrels of oil and/or natural gas liquids.
MMBtu	A unit of heat equal to one million British thermal units.
mcf	1,000 cubic feet of natural gas.
bbl or barrel	42 U.S. gallons liquid volume of crude oil or natural gas liquids.
Undeveloped reserves	Reserves that are expected to be recovered from known accumulation where a significant expenditure is required to render them capable of production (e.g. in comparison to the cost of drilling a well). Such reserves must fully meet the requirements of the reserves classification to which they are assigned (proved or probable).

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Form 51-101F1

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION FOR DYNAMIC OIL & GAS, INC.

This is the form referred to in item 1 of section 2.1 ofNational Instrument 51-101Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).

The following information is related to our reserves, future net revenue and discounted value of future net cash flow of natural gas, natural gas liquids, light/medium crude oil and heavy crude oil. Sproule Associates Limited (“Sproule”), independent qualified evaluators of Calgary, Alberta estimated these reserves effective December 31, 2004. We used these reserves in the preparation of our Financial Statements for the fiscal year ended December 31, 2004.

All our reserves are in Alberta, British Columbia and Saskatchewan, Canada.

The reserves on our properties described herein are estimates only. Actual reserves on our properties may be greater or less than those calculated.

The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the Sproule evaluation will be attained, and variances could be material. Assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables.

The following tables provide reserves data and a breakdown of future net revenue by commodity and reserve category using forecast prices and costs and/or constant prices and costs, based on our working interest portion before royalties (gross) and/or after royalties (net) (see “Glossary of Terms”).

The pricing used in tables that reflect constant and forecast price evaluations is set forth in Items 3.1 and 3.2, respectively.

In certain instances, numbers may not total due to computer-generated roundings. In such cases, differences are not material and amounts presented are as shown in the Sproule Report.

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Item 2.1 Reserves Data (Constant Prices and Costs)

Item 2.1(1)The following table shows our gross and net reserves by reserve category using constant prices and costs.

Summary of Reserves
Based on Constant Prices and Costs

	Light and
	Medium Oil		Heavy Oil		Natural Gas(1)		Natural Gas
							Liquids
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Reserve Category	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mmcf)	(mmcf)	(mbbl)	(mbbl)
Proved
Developed	205.3	172.9	314.3	248.4	14,300	11,859	835.5	689.2
producing
Developed non-
producing	13.5	11.7	82.5	67.7	672	528	6.6	5.2
Undeveloped	22.5	19.6	223.1	197.8	1,165	874	11.3	9.5
Total proved	241.3	204.2	619.9	513.9	16,137	13,261	853.4	703.9
Probable	408.7	337.8	711.6	599.2	11,044	8,829	378.9	313.7
Total proved plus
probable	650.0	542.0	1,331.5	1,113.1	27,181	22,090	1,232.4	1,017.6

⁽¹⁾ Includes solution gas.

Item 2.1(2)The following table shows the net present values of the future net revenue of our net reserves by reserve category using constant prices and costs.

Summary of Net Present Values of Future Net Revenue
Based on Constant Prices and Costs

($000’s)	Before Income Taxes				After Income Taxes
	Annual Discount Rate				Annual Discount Rate
Reserve Category	0	%	10	%	0	%	10	%
Proved
Developed producing	73,892		56,325		65,816		50,150
Developed non-producing	2,694		1,905		1,762		1,186
Undeveloped	3,719		2,357		2,368		1,309
Total proved	80,305		60,587		69,946		52,645
Probable	52,089		27,726		36,211		17,718
Total proved plus probable	132,394		88,313		106,157		70,363

Item 2.1(3)(a)The following table shows the net present values of the future net revenue of our and (b)net reserves by reserve category using constant prices and costs, undiscounted.

Total Future Net Revenue – Undiscounted
Based on Constant Prices and Costs

($000’s)						Future Net
					Well	Revenue		Future Net
Reserve			Operating	Development	Abandonment	Before Income	Income	Revenue After
Category	Revenue	Royalties	Costs	Costs	Costs	Taxes	Taxes	Income Taxes
Proved	156,341	28,902	42,112	3,678	1,342	80,305	10,359	69,946
Proved plus
probable	273,141	51,652	70,612	16,726	1,757	132,394	26,237	106,157

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Item 2.1(3)(c)The following table shows the net present values of the future net revenue of our net reserves by reserve category using constant prices and costs before deducting future income tax expenses using a 10% discount rate.

Future Net Revenue by Production Group
Based on Constant Prices and Costs

($000’s)		Future Net Revenue Before Income
Reserves Category	Production Group	Taxes – Discounted Annually @
		10%
Proved reserves	Light and medium crude oil(1)	4,265
	Heavy oil(1)	3,182
	Natural gas(2)	51,675
Proved plus probable	Light and medium crude oil(1)	9,417
	Heavy oil(1)	2,971
	Natural gas(2)	74,031

     ⁽¹⁾Includes solution gas and associated by-products.
    ⁽²⁾Includes associated by-products but excluding solution gas from oil wells.

Item 2.2 Reserves Data (Forecast Prices and Costs)

Item 2.2(1)The following table shows our gross and net reserves by reserve category using forecast prices and costs.

Summary of Reserves
Based on Forecast Prices and Costs

	Light and						Natural Gas
	Medium Oil		Heavy Oil		Natural Gas(1)		Liquids
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Reserve Category	(mbbl)	(mbbl)	(mbbl)	(mbbl)	(mmcf)	(mmcf)	(mbbl)	(mbbl)
Proved
Developed	181.6	152.3	299.3	239.2	14,033	11,633	826.7	682.0
Producing
Developed non-
Producing	13.5	11.7	126.4	103.6	677	532	6.4	5.1
Undeveloped	22.5	19.7	233.1	187.6	1,162	872	11.2	9.4
Total proved	217.6	183.7	648.8	530.4	15,872	13,037	844.3	696.5
Probable	383.2	317.3	727.6	602.2	10,744	8,570	371.5	307.8
Total proved plus
Probable	600.8	501.0	1,376.4	1,132.6	26,616	21,607	1,215.8	1,004.3

⁽¹⁾ Includes solution gas.

Item 2.2(2)The following table shows the net present value of future net revenue for our net reserves by reserve category using forecast prices and costs.

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Summary of Net Present Values of Future Net Revenue
Based on Forecast Prices and Costs

($000’s)	Before Income Taxes										After Income Taxes
Reserve	Annual Discount Rate										Annual Discount Rate
Category	0	%	5	%	10	%	15	%	20	%	0	%	5	%	10	%	15	%	20	%
Proved
Developed
producing	60,991		54,781		49,834		45,855		42,604		55,764		49,904		45,261		41,548		38,532
Developed
non-producing	3,137		2,769		2,481		2,248		2,055		2,075		1,758		1,519		1,330		1,177
Undeveloped	4,526		3,884		3,379		2,973		2,639		2,876		2,338		1,924		1,599		1,335
Total proved	68,654		61,434		55,694		51,076		47,298		60,715		54,000		48,704		44,477		41,044
probable	44,483		33,113		26,181		21,458		18,012		31,590		22,229		16,743		13,106		10,504
Total proved
plus probable	113,137		94,547		81,875		72,534		65,310		92,305		76,229		65,447		57,583		51,548

Item 2.2(3)(a)The following table shows the future net revenue of our net reserve by reserves and (b)category using forecast prices and costs, and undiscounted.

Total Future Net Revenue – Undiscounted
Based on Forecast Prices and Costs

($000’s)						Future Net
					Well	Revenue		Future Net
Reserve			Operating	Development	Abandonment	Before Income	Income	Revenue After
Category	Revenue	Royalties	Costs	Costs	Costs	Taxes	Taxes	Income Taxes
Proved	145,349	27,172	43,735	4,258	1,530	68,654	7,940	60,714
Proved
plus
probable	255,654	48,960	74,130	17,320	2,107	113,137	20,832	92,305

Item 2.2(3)(c) The following table shows the net present value of future net revenue of our net reserves by reserve category using forecast prices and costs before deducting future income tax expense, discounted at 10%.

Future Net Revenue by Production Group
Based on Forecast Prices and Costs

($000’s)		Future Net Revenue Before Income
Reserves Category	Production Group	Taxes – Discounted Annually @ 10%
Proved reserves	Light and medium crude oil(1)	3,801
	Heavy oil(1)	7,995
	Natural gas(2)	42,542
Proved plus probable	Light and medium crude oil(1)	7,537
	Heavy oil(1)	12,946
	Natural gas(2)	59,685

⁽¹⁾ Includes solution gas and associated by-products.
⁽²⁾ Includes associated by-products but excluding solution gas from oil wells.

Item 2.3 Reserves Disclosure Varies with Accounting

We have no subsidiary interests.

Item 2.4 Future Net Reserves Disclosure Varies with Accounting

We have no subsidiary interests.

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Item 3.1 Constant Prices Used in Estimates

The following table shows benchmark reference prices that have been used by Sproule in evaluating our reserves.

Summary of Pricing Assumptions
Based on Constant Prices and Costs

Crude Oil		Natural Gas		Natural Gas Liquids
Edmonton Par	Hardisty Heavy,	Alberta	B.C. West			Pentanes
Price	1212º API Oil	AECO-C	Coast Stn 2	Propane	Butane	Plus
($Cdn/stb)	($Cdn/stb)	($Cdn/MMBtu)	($Cdn/MMBtu)		($Cdn/bbl)
46.51	15.26	6.78	6.68	36.11	39.78	51.80

Item 3.2 Forecast Prices Used in Estimates

The following table shows historical and future pricing and inflation rate assumptions used by Sproule in evaluating our reserves.

Summary of Pricing and Inflation Rate Assumptions
Based on Forecast Prices and Costs

	Crude Oil		Natural Gas		Natural Gas Liquids
	WTI	Edmonton	Hardisty	Natural Gas(1)	Pentanes	Butanes
Year	Cushing	Par Price	Heavy	AECO Gas	plus FOB	FOB Field	Inflation	Exchange
	Oklahoma	40oAPI	12oAPI	Prices	Field Gate	Gate	Rates	Rate(3)
Historical	($US/bbl)	($Cdn/bbl)	($Cdn/bbl)	($Cdn/MMBtu)	($Cdn/bbl)	($Cdn/bbl)	%/Yr(2)	($US/$Cdn)
2001	25.94	39.06	18.05	6.23	42.46	27.93	2.0	0.646
2002	26.09	40.12	27.58	4.04	40.80	25.39	2.7	0.637
2003	31.14	43.23	27.39	6.66	44.16	34.55	2.5	0.716
2004	41.41	52.91	30.40	6.87	53.90	41.38	2.5	0.770
Forecast
2005	44.29	51.25	28.91	6.97	52.49	38.20	2.5	0.840
2006	41.60	48.03	28.12	6.66	49.19	34.01	2.5	0.840
2007	37.09	42.64	26.19	6.21	43.67	30.20	2.5	0.840
2008	33.46	38.31	25.06	5.73	39.23	27.13	2.5	0.840
2009	31.84	36.36	23.60	5.37	37.24	25.75	1.5	0.840
Thereafter				Various Escalation Rates

⁽¹⁾ This summary table identifies benchmark reference pricing schedules that might apply to areporting issuer.
⁽²⁾ Inflation rates for forecasting prices and costs.
⁽³⁾ Exchange rates used to generate the benchmark reference prices in this table.

Notes: Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale.

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Item 4.1ReservesReconciliation

Item4.1(1)The following table sets forth a year-over-year reconciliation of the changes in our net light and medium crude oil, heavy oil and natural gas and natural gas liquids reserves.

Reconciliation ofCompanyInterest NetReserves(AfterRoyalties)
Based onConstant Prices and Costs

	Light/Medium Oil					Heavy Oil						Natural Gas						Natural Gas Liquids
				Net						Net						Net						Net
				Proved						Proved						Proved						Proved
			Net	plus		Net		Net		plus		Net		Net		plus		Net		Net		plus
	Net Proved		Probable	Probable		Proved		Probable		Probable		Proved		Probable		Probable		Proved		Probable		Probable
	(mbbl)		(mbbl)	(mbbl)		(mbbl)		(mbbl)		(mbbl)		(mmcf)		(mmcf)		(mmcf)		(mbbl)		(mbbl)		(mbbl)
December 31, 2003
Remaining Reserves	407		245	652		4		1		5		19,553		13,685		33,238		813		323		1,136
Extensions	30		-	30		-		-		-		128		267		395		4		8		12
Improved Recovery	41		-	41		-		-		-		1,170		-		1,170		74		-		74
Discoveries	-		-	-		438		480		918		187		166		353		-		-		-
Economic Factors	-		-	-		(16	)	(2	)	(18	)	224		232		456		7		7		14
Technical Revisions	(216	)	93	(123	)	-		-		-		(4,572	)	(5,529	)	(10,101	)	(24	)	(24	)	(48	)
Acquisition	-		-	-		105		120		225		7		8		15		-		-		-
Production	(58	)	-	(58	)	(17	)	-		(17	)	(3,436	)	-		(3,436	)	(170	)	-		(170	)
December 31, 2004
Remaining Reserves	204		338	542		514		599		1,113		13,261		8,829		22,090		704		314		1,018

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Item 4.2 Future Net Revenue Reconciliation

The following table sets forth changes between future net revenue estimates attributable to our net proved reserves as at December 31, 2004 compared to such reserves as at January 1, 2004, using constant prices and costs.

Reconciliation of Changes in Net Present Values of Future Net Revenue
Discounted at 10% per year
Proved Reserves – Constant Prices and Costs

	2004
Period and Factor	($M)
Estimated Future Net Revenue After Tax at Beginning of Year(1)	64,397
Sales and Transfers of Oil & Gas Produced. Net of Production Costs and Royalties	(23,300	)
Net Change in Prices, Production Costs and Royalties Related to Future Production	(1,392	)
Change in Previously Estimated Development Costs Incurred During the Period	8,868
Change in Estimated Future Development Costs	(3,402	)
Net Change from Extensions and Improved Recovery	6,623
Net Change from Discoveries	1,556
Net Change due to Acquisitions	377
Net Change due to Technical Revisions	(21,675	)
Accretion of Discount	4,989
Net Change in Income Taxes	15,604
Miscellaneous Change	- -
Estimated Future Net Revenue at End of Year	52,645

⁽¹⁾ Includes tax pools at beginning of year.

Item 5.1 Undeveloped Reserves

Item 5.1(1)The following table sets forth the volumes of proved undeveloped reserves that were attributed for each of our reserve categories.

Proved Undeveloped Reserves by Year – Constant Prices and Costs

	Light and Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids
Period	(mbbl)	(mbbl)	(mmcf)	(mbbl)
2003	158	- -	3,678	20
2004	22	223	1,165	11

Of our total proved reserves as at December 31, 2004, only 10% were undeveloped. Most of our undeveloped proved reserves are located where there is capital required to tie in tested wells. A portion of these projects have already been completed in the first quarter of 2005 and the remaining projects are expected for completion by the end of 2005. One of the projects is not scheduled for completion until the currently-producing zone is depleted.

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Item 5.1(2) Probable Undeveloped Reserves

Of our total probable reserves as at December 31, 2004, approximately 40% are classified as undeveloped. These probable undeveloped reserves relate to drilling projects at Cypress and Orion, British Columbia, St. Albert, Alberta and Mantario East, Saskatchewan, and a compressor project at St. Albert, Alberta. All of these projects are scheduled for completion in Fiscal 2005.

Item 5.2 Significant Factors and Uncertainties

The process of evaluating reserves is inherently complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. These factors and assumptions include among others: (i) historical production in the area compared with production rates from analogous producing areas; (ii) initial production rates; (iii) production decline rates; (iv) ultimate recovery of reserves; (v) success of future development activities; (vi) marketability of production; (vii) effects of government regulation; and (viii) other government levies imposed over the life of the reserves.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions. Revisions to reserve estimates can arise from changes in year-end prices, reservoir performance and geologic conditions or production. These revisions can be either positive or negative.

Item 5.3 Future Development Costs

The table below sets out the future development costs deducted in the estimation of future net revenue attributable to proved reserves (using both constant and forecast prices and costs) and proved plus probable reserves (using forecast prices only).

Future Development Costs
	Total Proved	Total Proved	Total Proved Plus Probable
($ 000’s)	Estimated Using	Estimated Using	Estimated Using
Period	Constant Prices and Costs	Forecast Prices and Costs	Forecast Prices and Costs
2005	3,148	3,680	16,653
2006	90	92	92
2007	90	95	95
2008	-	-	-
2009	188	207	207
Total for all years
- undiscounted	3,678	4,258	17,320
- 10% discounted	3,443	4,003	16,569

The future development costs are capital expenditures required in the future for us to convert proved undeveloped reserves and probable reserves into proved developed producing reserves.

On an ongoing basis, we will typically use internally-generated cash flow from operations, debt (where deemed appropriate) and new equity issues if available on favourable terms to finance our capital investment program. When financing corporate acquisitions, we may also assume certain future liabilities.

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Item 6.1 Oil and Gas Properties and Wells

Item 6.1(1) Important Properties, Plants, Facilities and Installations

The following is information describing our important properties, plants, facilities and equipment.

St. Albert, Alberta	St. Albert is located in central Alberta, northwest of the City of Edmonton and near the City of St. Albert.
Geological Description	The property is comprised of two reef structures that are associated with 16, separate pools of Cretaceous Age natural gas and Devonian Age crude oil that are stacked in seven productive formations. Four of the productive formations are natural gas and three are crude oil.For purposes of project identification, we refer to the two reef structures as the “north pool” and the “south pool”. In aggregate, both structures have historically produced in excess of 23.7 million barrels of crude oil and 121 billion cubic feet of raw natural gas.
Land Holdings	We own 8,101 net acres (12,839 gross) of various crown and freehold petroleum and natural gas leases for a weighted average working interest of 63%. Of our net acreage, 28% is undeveloped.
Seismic	We own a 37.5% working interest in a proprietary 3D seismic database covering 12 square kilometers.
Wells and Facilities	We own a weighted average 75% working interest in 16 producing gas wells and a 75% working interest in nine producing oil wells. In addition, we own a 75% working interest in one oil battery, two saltwater disposal wells, one solution gas plant, one sour gas compressor, two sweet gas compressors and a 13 kilometer, 6” sour gas pipeline.
Fiscal 2004 Activities	In the north pool we drilled one successful well targeting remaining oil reserves in the Leduc D-3 formation and Wabamun D-1 formation. The well is completed in both formations and is presently producing oil from the Wabumun D-1 formation. Also in the north pool, we drilled one unsuccessful well targeting shallow gas in the Belly River and Edmonton formations. In the south pool, we acquired a new water disposal well to address future water handling and disposal associated with our oil production. We re-completed two existing natural gas wells in the Ostracod formation to further optimize sweet gas production. Further, we optimized our sweet gas compressor and upgraded our salt-water disposal facilities.
Fiscal 2005	Outlook Our Fiscal 2005 budget continues to focus on production optimization. Two capital projects are planned to slow the natural decline rate of oil and gas production and to improve operating efficiencies. All projects are geared toward enhanced recovery of remaining crude oil and natural gas reserves from known pools. One development well is planned for Fiscal 2005 targeting remaining oil in the Leduc D-3 and Wabamun D-1 formations in the north pool.

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	Our investment at St. Albert includes numerous wells and facilities in close proximity to urban areas. For this reason, we will continue our commitment to “STAMP” (“St. Albert and Area Multi-Stakeholder Project”), which we helped create to bring oil and gas operators, regulators, local government and special interest groups together in a forum for open dialog and information exchange.
Halkirk, Alberta	Halkirk is located in central Alberta approximately 168 kilometers northeast of Calgary.
Geological Description	This area is prospective for multiple, sweet natural gas-bearing Cretaceous Age sandstone reservoirs. The primary target for reserves is the Viking formation with an average net pay thickness of approximately five meters.
Land Holdings	We own 6,336 net acres (6,720 gross) of crown and freehold petroleum and natural gas leases for a weighted average working interest of 94%. Of our net acreage, 45% is undeveloped.
Wells and Facilities	We own a 100% working interest in four producing Viking gas wells and an 80% working interest (before payout of our initial capital expenditures), in three producing Viking gas wells. After payout, our working interest will convert to 48%. All of our natural gas production is processed at the Maple Glen Gas Plant under a custom processing agreement with the plant’s third-party owner.
Fiscal 2004	Activities During the year, production operations were maintained without significant capital expenditures.
Fiscal 2005	Outlook Two infill development wells are planned and will target sweet natural gas in the Viking formation. Our existing gathering system will accommodate production from these wells.
Peavey/Morinville	Peavey/Morinville is located a short distance from our St. Albert field and is approximately 19 kilometers north of the City of Edmonton.
Geological Description	The area is comprised of natural-gas bearing sandstones and shales of Cretaceous Age that are structurally draped over highs in the Leduc D-3 formation.
Land Holdings	We own 6,998 net acres (10,243 gross) of petroleum and natural gas rights for a weighted average working interest of 68%. Of our total net holdings, 33% is undeveloped.
Seismic	We own a licensed copy of a high quality, 3D seismic database covering 14 square kilometers.
Wells and Facilities	We own a weighted average working interest of 77% in six producing natural gas wells.
Fiscal 2004	Activities During the year, we equipped, tied in and began producing from one natural gas well that was drilled in a prior year. All other production operations were maintained without significant capital expenditures.
Fiscal 2005	Outlook Tie-in of one well and recompletion of another is planned for early in Fiscal 2005.

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Cypress/Chowade, British Columbia	Cypress/Chowade is located in the foothills of northern British Columbia approximately 100 kilometers northwest of Fort St. John.
Geological Description	The area is prospective for multiple, natural gas-bearing Triassic Age and deep Mississippian Age carbonate reservoirs contained within classic foothill anticlines that trend northwest/southeast through the area.
Land Holdings	We have crown petroleum and natural gas leases over 19,911 net acres (56,675 gross) for a weighted average working interest of 35%. Of our total net acreage, 75% is undeveloped.
Seismic	Our seismic database contains a total of 440 kilometers of licensed, trade 2D seismic data, as well as a 100% working interest in 15 kilometers of 2D proprietary seismic data.
Wells and Facilities	We have four producing and six standing natural gas wells. In the four producing wells, we own a 50% working interest. Our working interests in the six standing wells are: 50% in three wells; 100% in one; 30% in one; and 20% in the remaining well. In four of the ten wells in which we own a 50% working interest, our interest converts to a 30% working interest after payout. In addition, we own approximately 40% of an 8”, 19-kilometer sales line that crosses beneath the Halfway River and connects Cypress to the Sikanni Gas plant. We split delivery of our 2004 gas production to Cypress Gas Plant and Sikanni Gas Plant under separate third-party custom processing agreements.
Fiscal 2004	Activities We participated in drilling five wells and completed an untested zone in an existing wellbore. These wells targeted multi-zone, natural-gas bearing reservoirs of Triassic and Mississippian Ages. Our working interests in the wells were: one at 100% working interest; three at 50%; and two at 30%. Of the five wells that were drilled, three were completed as potential natural gas wells and two were unsuccessful. We also participated in the construction of the 8”, 19-kilometer pipeline mentioned above. We also acquired 4,394 net acres (11,544 gross). During Fiscal 2004, costs related to three wells that were drilled and completed in Fiscal 2003 because the wells could not be classified as having proved reserves. Our working interest in two of these wells was 30% and 50% in the other.
Fiscal 2005 Outlook	We plan to participate, at a 30% working interest, in drilling two exploratory outpost wells and shoot 15 kilometers of 2D seismic. We also plan to have two of our six standing shut-in gas wells on stream in the first quarter of Fiscal 2005. The remaining two shut-in wells require further development in the area to meet threshold reserves necessary for tie-in. In addition, we have budgeted for our 30% share of the cost to add field compression. The current processing capacities of two gas plants in the area are expected to meet our processing needs in Fiscal 2005. We will continue to monitor and evaluate land acquisition opportunities in the area.

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Orion, British Columbia	Orion is strategically located between the Sierra and Helmet natural gas fields approximately 56 kilometers west of the Alberta border and 112 kilometers south of the Northwest Territories border. The property is dissected by the Sierra Yoyo Desan Road, which provides year-round access for drilling operations. A large independent Canadian oil and gas company has referred to the regional Devonian Age Jean Marie carbonate reservoir in this area as “The Greater Sierra Gas Play” and has described the area as the largest gas play discovered in Western Canada. Orion is a part of this area and is a key element in our long-term growth strategy.
Geological Description	The area is prospective for natural gas exploration and development in Cretaceous Age Bluesky sandstone reservoirs and Mississippian and Devonian Age Debolt, Jean Marie and Slave Point formation carbonate reservoirs.
Land Holdings	We hold under lease 46,802 net acres (66,614 gross) for a weighted average working interest of 70%. Approximately 91% of our net holdings are undeveloped.
Wells and Facilities	We own a 15% gross overriding royalty interest (before payout of our initial capital expenditures) in one potential Jean Marie gas well and a 100% working interest in one potential Bluesky gas well. The gross overriding royalty interest will convert to a 50% working interest after payout. Both wells are standing and awaiting further evaluation and area development. We also own a 100% working interest in two other standing cased wells with potential value for purposes of side-track drilling or water disposal.
	Two major pipeline systems terminate at the edge of our property. To the southwest, the Duke Energy Pipeline System connects to Fort Nelson for delivery to Washington State and to the northeast. The Duke Energy Field Services Pipeline System connects to Tooga Compressor Station for delivery to Alberta.
Fiscal 2004 Activities	During the first quarter, we conducted a two-phase 3D seismic program covering 90 square kilometers of the property. Interpretation of the seismic has identified several drillable targets on our land. During the third and fourth quarters, we drilled three wells targeting gas in the Bluesky and Jean Marie formations. Two of these wells were drilled at a 100% working interest and one well was drilled at a 50% working interest. One of the 100% wells has been production tested and cased as a potential gas well and the other two wells were unsuccessful. We drilled one well at 100% working interest, targeting gas in the Slave Point formation. The Slave Point well was cased and production tested but did not produce commercial quantities of gas. The well is a standing gas well with further sidetrack drilling potential. During Fiscal 2004, costs related to two wells that were drilled and completed in Fiscal 2003 were expensed due to unsuccessful efforts to develop proved reserves. Our working interest in these two these wells was 100%.
Fiscal 2005 Outlook	We plan to drill one development well in the first quarter, targeting gas in a producing Bluesky gas pool that directly offsets company-

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	owned lands. We also plan to drill one exploration well in the fourth quarter targeting gas in a similar, but separate, Bluesky structure. Both wells are planned at 100% working interest.
Mantario East, Saskatchewan	Mantario East is located 30 kilometers southwest of the Town of Kindersley and 30 kilometers east of the Alberta Border.
Geological Description	The area is prospective for multiple Cretaceous, Mississippian and Devonian aged sandstone and carbonate reservoirs. Primary targets include natural gas-bearing Viking, Upper Mannville and Bakken formations and heavy-oil in the Basal Mannville and Birdbear formations.
Land Holdings	We hold under lease 7,502 net acres (12,603 gross) for a weighted average working interest of 60%. Approximately 81% of our net holdings are undeveloped.
Wells and Facilities	We have 11 heavy-oil wells at Mantario East - five are in production and six are standing awaiting tie-in. In three of the five producing wells, our ownership is a 100% working interest (before payout of our original capital expenditures), converting to a 75% working interest after payout. In the two producing and the six standing wells, we own a 75% working interest. At Sandgren, we own a 100% working interest before payout in one cased and standing gas well that converts to a 75% working interest after payout.
Fiscal 2004 Activities	We discovered a new pool of oil in the Basal Mannville at Mantario East. The oil is classified by regulation as Basal Mannville heavy-gravity crude. The nearest analogs to our heavy-oil discovery is located directly west of us on lands owned by others (non-owned) at Marengo, Mantario North, and Mantario East. The nearest pools on non-owned lands at Mantario East, have produced over three million barrels of heavy-oil from 36 wells in pool sizes of approximately 800 acres. On our lands at Mantario East, the number of pools and their sizes has not yet been determined. In total, we drilled 15 wells in the Mantario area during the third and fourth quarter of Fiscal 2004. Of these, five were earning wells drilled at 100% working interest under a farmout agreement and 10 were non-earning wells drilled at 75% with an industry partner. The 15-well drilling program resulted in: five producing heavy crude oil wells, six cased and standing heavy crude oil wells; one cased and standing natural gas well; and three unsuccessful wells.
Fiscal 2005 Outlook	We have budgeted to drill four exploration oil and/or natural gas wells and a 15-well in-fill drilling program targeting Basal Mannville oil, a gathering system and an oil battery facility in Fiscal 2005. We also plan to equip and tie-in two of six standing oil wells in the first quarter of Fiscal 2005 and the remaining four in the second quarter. Funds have also been budgeted to acquire additional lands and seismic in the area. The gathering system and oil battery is a two-phase construction project. Phase I is scheduled for completion by April 1, 2005 and will include tie-in of eight oil wells to a central oil battery facility capable of processing up to 1,500 barrels of oil per day. Phase II will include tie-in of remaining wells as they are drilled and will expand the oil

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	processing capacity of the battery to 2,500 barrels per day from an estimated 25 wells.
Other Non-Core Properties	Alberta properties include: Alexander; Stanmore; Westlock;Simonette; and Quirk Creek. Saskatchewan properties include: Elmore; and Rapdan. In total, these properties comprise 9,064 net acres (13,769 gross) with a weighted average working interest of 66%. Of our total net acreage, 71% is undeveloped.

Item 6.1(2) Oil and Gas Wells

The following table sets forth the number and status of wells in which we had a working interest as at December 31, 2004. The stated interests are subject to landowner’s and other royalties, where applicable, in addition to usual crown royalties and mineral taxes. All the following wells are located in the Western Provinces of Canada, as noted.

	Producing				Non-Producing
	Oil		Natural Gas		Oil		Natural Gas
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
Alberta
Alexander	-	-	1	1.0	-	-	-	-
St. Albert	6	4.5	23	17.1	-	-	16	11.9
Halkirk	-	-	8	7.4	-	-	4	4.0
Wimborne	-	-	-	-	-	-	3	2.0
Redwater	-	-	-	-	-	-	1	1.0
Stanmore	-	-	1	0.7	-	-	-	-
Westlock	-	-	1	0.9	-	-	-	-
Peavey/
Morinville	-	-	5	3.1	-	-	20	16.2
Simonette	-	-	1	0.5	-	-	-	-
Virgo	-	-	1	0.1	-	-	-	-
British Columbia
Cypress/
Chowade	-	-	5	2.3	-	-	6	2.7
Orion	-	-	1	1.0	-	-	3	2.0
Saskatchewan
Mantario
East	9	7.5	-	-	4	3.3	-	-
Elmore	-	-	3	0.2	-	-	-	-
Rapdan	1	0.1	-	-	-	-	-	-
Flaxcombe	-	-	-	-	-	-	1	0.6
Sandgren	-	-	1	1.0	-	-	-	-
Total	16	12.1	51	35.3	4	3.3	54	40.4

⁽¹⁾ “Gross” wells are defined as the total number of wells in which we have an interest.
⁽²⁾“Net” wells are defined as the aggregate of the numbers obtained by multiplying each gross well by our percentage working interest therein.

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Item 6.2 Undeveloped Properties Having No Attributed Reserves

Wimborne, Alberta	Wimborne is located in south-central Alberta approximately 112 kilometers northeast of Calgary.
Geological Description	The area is prospective for multiple Cretaceous Age sandstone reservoirs containing natural gas and natural gas liquids. Additional potential exists for crude oil and natural gas within deeper Mississippian and Devonian Age carbonate reservoirs.
Land Holdings	We own 7,755 net acres (9,675 gross) of petroleum and natural gas rights for a weighted average working interest of 80%. Of our total net holdings, 74% is undeveloped.
Seismic	We own a licensed copy of a high quality, 3D seismic database covering 260 square kilometers.
Wells and Facilities	We own a 100% working interest in one standing gas well. The property is in close proximity to existing natural gas pipelines and processing facilities.
Fiscal 2004 Activities	We participated at a 50% working interest in the drilling of two wells targeting gas in Cretaceous Age formations. Both wells were unsuccessful.
Fiscal 2005 Outlook	Our large 3D seismic database has identified multiple undrilled exploration targets on our lands. While we have no drilling plans for Fiscal 2005, the area remains prospective for third-party farmout opportunities.
Cypress/Chowade, British Columbia	Cypress/Chowade is located in the foothills of northern British Columbia approximately 100 kilometers northwest of Fort St. John.
Land Holdings	We have crown petroleum and natural gas leases over 19,911 net acres (56,675 gross) for a weighted average working interest of 35%. Of our total net acreage, 75% is undeveloped.
Fiscal 2004 Activities	We participated in drilling five wells and completed an untested zone in an existing wellbore. These wells targeted multi-zone, natural-gas bearing reservoirs of Triassic and Mississippian Ages. Our working interests in the wells were: one at 100% working interest; three at 50%; and two at 30%. Of the five wells that were drilled, three were completed as potential natural gas wells and two were unsuccessful. We also participated in the construction of the 8”, 19-kilometer pipeline mentioned above. We also acquired 4,394 net acres (11,544 gross). During Fiscal 2004, costs related to three wells that were drilled and completed in Fiscal 2003 were expensed due to unsuccessful efforts to develop proved reserves. Our working interest in two of these wells was 30% and 50% in the other.
Fiscal 2005 Outlook	We plan to participate, at a 30% working interest, in drilling two exploratory outpost wells and shoot 15 kilometers of 2D seismic. We also plan to have two of our four standing shut-in gas wells on stream in the first quarter of Fiscal 2005. The remaining two shut-in wells require further development in the area to meet threshold

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	reserves necessary for tie-in. In addition, we have budgeted for our 30% share of the cost to add field compression. The current processing capacities of two gas plants in the area are expected to meet our processing needs in Fiscal 2005. We will continue to monitor and evaluate land acquisition opportunities in the area.
Fraser Valley (Under Moratorium)	The property is located in the lower mainland area of southwestBritish Columbia near Vancouver.
Land Holdings	Under a joint venture agreement with Conoco Canada Limited, we continue to hold a weighted average working interest of 34% in approximately 18,278 net acres (54,502 gross) of undeveloped onshore and offshore petroleum and natural gas rights associated with Permit 802, a validated British Columbia Exploration Permit. Permit 802 is under provincial jurisdiction and includes offshore petroleum and natural gas rights in the Georgia Basin, located in the Strait of Georgia between the Lower Mainland and Vancouver Island.
Fiscal 2004 Activities	We were inactive in the Fraser Valley area during Fiscal 2004.
Fiscal 2005 Outlook	Presently, areas offshore are subject to a restricted-access moratorium for petroleum and natural gas activities, however, discussions are underway between the Provincial and Federal Governments in regards to lifting the moratorium. The Provincial Government has indicated its desire to move forward and the Federal Government is currently conducting a public review to identify environmental and social concerns arising from offshore activities along the Pacific West Coast. A final decision on the matter is not expected in 2005. We have identified through analysis of our proprietary onshore 2D seismic data, a large structural feature approximately 19 square kilometersin size extending offshore. Government-owned gravity data supports our interpretations and refers to the feature as the Robert’s Bank Gravity Anomaly. The Geological Survey of Canada has assigned the Georgia Basin a reserve estimate of 6.5 trillion cubic feet of natural gas. A commercial quantity of gas is yet to be discovered in the area. We plan to be inactive in the Fraser Valley in 2005.

Item 6.3 Forward Contracts

We have no forward contracts as at December 31, 2004.

Item 6.4 Additional Information Concerning Abandonment and Reclamation Costs

The following table discloses the abandonment and reclamation costs of our anticipated costs at December 31, 2004, calculated on an undiscounted and a 10% discount rate with a portion thereof anticipated for settlement in each of the next three years. We currently anticipate incurring abandonment and reclamation costs in respect of 91.1 net wells.

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Abandonment and Reclamation Costs Net of Salvage Value

($000s)	2005	2006	2007	2008	2009	2010	2011	Remainder	Total	Discounted
										at 10%
Wells with reserves
assigned	46	160	127	168	78	42	242	1,013	1,876	717
Wells with no
reserves assigned	83	153	133	142	132	25	111	962	1,741	677
Plants	-	-	-	-	-	-	-	1,044	1,044	197
Total	129	313	260	310	210	67	353	3,019	4,661	1,591

Item 6.5 Tax Horizon

We are not required to pay income taxes with respect to our Fiscal 2004.

Item 6.6 Costs Incurred

The following table summarizes the capital expenditures made by us on oil and natural gas properties for the fiscal year ended December 31, 2004.

Costs Incurred

Property Acquisition Costs		Exploration Costs	Development Costs
(M$)		(M$)	(M$)
Proved Properties	Unproved Properties
66	4,088	18,488	13,969

We own interests in certain properties located in the Western Provinces of Canada. For purposes of identification, discussion and differentiation, we have named them based on their location. They are as follows:

			Southern
Central Alberta		British Columbia	Saskatchewan
St. Albert	Westlock	Cypress/Chowade	Mantario East
Halkirk	Simonette	Orion	Elmore
Peavey/Morinville	Wimborne	Fraser Valley	Rapdan
Alexander	Quirk Creek		Flaxcombe
Stanmore			Sandren

Item 6.7 Exploration and Development Activities

The following table sets forth the number of exploratory and development wells which we completed during our 2004 financial year.

	Exploratory Wells		Development Wells
	Gross(1)	Net(2)	Gross(1)	Net(2)
Oil Wells	4	4.0	8	6.1
Gas Wells	4	4.0	2	0.8
Dry Holes	4	2.5	6	4.6
Total Completed Wells	12	10.5	16	11.5

⁽¹⁾ “Gross” wells are defined as the total number of wells in which we have an interest.
⁽²⁾ “Net” wells are defined as the aggregate of the numbers obtained by multiplying each gross well by our percentage working interest therein.

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Item 6.8 Production Estimates

The following table sets forth our estimated total production volumes for Fiscal 2005. Our fields at St. Albert and Mantario East are the only fields that individually meet or exceed 20% of our estimated total production.

	Light & Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids
Total Proved	(mbbl)	(mbbl)	(mmcf)	(mbbl)
All Fields	54,000	311,000	3,989	168,000
St. Albert	54,000	- -	2,593	168,000
Mantario East	- -	311,000	- -	- -

Item 6.9 Production History

Item 6.9(1)The following table sets forth certain information in respect of production,product prices received, royalties, production costs and netbacks received by us for each quarter of our Fiscal 2004.

	Three Months	Three Months	Three Months	Three Months
	Ended	Ended	Ended	Ended
	March 31, 2004	June 30, 2004	Sept. 30, 2004	Dec. 31, 2004
Average Daily Production
Light and Medium Oil (bbl/d)	273	170	111	145
Heavy Oil (bbl/d)	- -	- -	- -	242
Natural Gas (mcf/d)	13,644	12,936	12,435	11,703
Natural Gas Liquids (bbl/d)	684	512	535	554
Average Net Prices
Received(1)
Light and Medium Oil ($/bbl)	49.57	40.70	55.02	57.14
Heavy Oil ($/bbl)	- -	- -	- -	21.07
Natural Gas ($/mcf)	6.90	6.87	6.51	6.70
Natural Gas Liquids ($/bbl)	28.25	26.02	32.85	33.35
Royalties
Light and Medium Oil ($/bbl)	8.27	10.84	11.32	14.45
Heavy Oil ($/bbl)	- -	- -	- -	4.79
Natural Gas ($/mcf)	1.66	1.70	1.64	1.34
Natural Gas Liquids ($/bbl)	3.79	3.74	4.96	3.93
Production Costs
Light and Medium Oil ($/bbl)	5.87	11.21	28.14	14.07
Heavy Oil ($/bbl)	- -	- -	- -	3.25
Natural Gas ($/mcf)	..99	1.37	1.40	1.76
Natural Gas Liquids ($/bbl)	7.26	8.12	8.89	9.42
Netback Received
Light and Medium Oil ($/bbl)	35.43	18.65	15.56	28.62
Heavy Oil ($/bbl)	- -	- -	- -	13.03
Natural Gas ($/mcf)	4.25	3.80	3.47	3.60
Natural Gas Liquids ($/bbl)	17.20	14.16	19.00	19.99

⁽¹⁾Unit production cost measures by reserve category require certain allocations to by-products.

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Item 6.9(2)The following table shows our total production before royalties during Fiscal 2004 from our core property, St. Albert.

	Light & Medium Oil	Heavy Oil	Natural Gas	Natural Gas Liquids
Total Proved	(mbbl)	(mbbl)	(mmcf)	(mbbl)
St. Albert	64	- -	2,779	208

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Form 51-101F2

REPORT ON RESERVES DATA BY INDEPENDENT
QUALIFIED RESERVES EVALUATOR OR AUDITOR

Report on Reserves Data

To the Board of Directors of Dynamic Oil & Gas Inc. (the “Company”):

1. We have evaluated the Company’s Reserves Data as at December 31, 2004. The reserves data consist of the following:

(a)(i)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs; and
(ii)	the related estimated future net revenue; and
(b)(i)	proved oil and gas reserve quantities were estimated as at December 31, 2004 using constant prices and costs; and
(ii)	the related estimated future net revenue.

2.

The Reserves Data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Reserves Data based on our evaluation. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3.

Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

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4. The following table sets forth the estimated future net revenue attributed to proved plus probable reserves, estimated using forecast prices and costs on a before tax basis and calculated using a discount rate of 10%, included in the reserves data of the Company evaluated by us as of December 31, 2004, and identifies the respective portions thereof that we have audited, evaluated and reviewed and reported on to the Company’s management and Board of Directors:

Independent			Net Present Value of Future Net Revenue
Qualified			(10% Discount Rate)
Reserves	Description	Location of
Evaluator or	and Preparation Date	Reserves	Audited	Evaluated	Reviewed	Total
Auditor	of Evaluation Report	(Country)	(M$)	(M$)	(M$)	(M$)
Sproule	Evaluation of the P&NG	Canada
	Reserves of Dynamic Oil
	& Gas Inc., as of
	December 31, 2004
	prepared December				��
	2004 to January 2005
Total			Nil	81,875	Nil	81,875

5.	In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook.
6.	We have no responsibility to update the report referred to in paragraph 4 for events and circumstances occurring after its preparation date.
7.	Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

Sproule Associates Limited
Calgary, Alberta
February 4, 2005

“Cameron P. Six”
Cameron P. Six, P.Eng.
Senior Petroleum Engineer

“Michael Maughan”
Michael W. Maughan, C.P.G., P.Geol.
Manager, Geoscience, & Associate

“Robert N. Johnson”
Robert N. Johnson, P.Eng.
Manager, Engineering,
And Corporate Secretary

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Form 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS
ON OIL AND GAS DISCLOSURE

This is the form referred to in item 3 of section 2.1 ofNational Instrument 51-101

Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). This form does not apply in British Columbia

1.	Terms to which a meaning is ascribed inNI 51-101 have the same meaning in this form. {1}
2.	The report referred to in item 3 of section 2.1 ofNI 51-101 shall in all material respects be as follows:

Report of Management and Directors
On Reserves Data and Other Information

Management of Dynamic Oil & Gas, Inc. (the “Company”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

a)	proved and proved plus probable oil and gas reserves estimated as at December 31, 2004 using forecast prices and costs;
b)	the related estimated future net revenue;
c)	proved oil and gas reserves estimated as at December 31, 2004 using constant prices and costs; and
d)	the related estimated future net revenue.

Sproule Associates Limited, an independent qualified reserves evaluator, has evaluated the Company’s reserves data. The report of Sproule Associates Limited is presented above on Form 51-101F2.

The Reserves Audit Committee of the Board of Directors of the Company has:

a)	reviewed the Company’s procedures for providing information to Sproule Associates Limited;
b)	met with Sproule Associates Limited to determine whether any restrictions affected the ability of Sproule Associates Limited to report without reservation; and
c)	reviewed the reserves data with Management and Sproule Associates Limited.

The Reserves Audit Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with Management. The Board of Directors has, on the recommendation of the Reserves Audit Committee, approved:

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a)	the content and filing with securities regulatory authorities of the reserves data and other oil and gas information;
b)	the filing of the report of Sproule Associates Limited on the reserves data; and
c)	the content and filing of this report.

The reserves data are based on judgements regarding future events. Actual results may vary and the variations may be material.

“Wayne J. Babcock”

________________________________
Wayne J. Babcock
President & Chief Executive Officer

“Michael A. Bardell”

________________________________
Michael A. Bardell
Chief Financial Officer & Corporate Secretary

“William B. Thompson”

________________________________
William B. Thompson
Director

“John Lagadin”

________________________________
John Lagadin
Director

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