Dynamic Oil & Gas 20F 2004 Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 20-F

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

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

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

Commission File Number 0-17551

DYNAMIC OIL & GAS, INC.
(formerly Dynamic Oil Limited)
(Exact name of Registrant as specified in its charter)

Province of British Columbia (Canada)
(Jurisdiction of incorporation or organization)

#230 – 10991 Shellbridge Way
Richmond, British Columbia V6X 3C6, Canada
(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:
Common Stock Without Par Value

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None

The number of outstanding shares of our Common Stock outstanding as of December 31, 2004 was 24,558,978.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark which financial statement item the registrant has elected to follow. Item 17. x Item 18. ¨

TABLE OF CONTENTS

		Page

Glossary of Terms		3

Part I.
Item 1.	Identity of Directors, Senior Management and Advisers	7
Item 2.	Offer Statistics and Expected Timetable	7
Item 3.	Key Information	7
Item 4.	Our Information	15
Item 5.	Operating and Financial Review and Prospects	41
Item 6.	Directors, Senior Management and Employees	62
Item 7.	Major Shareholders and Related Party Transactions	73
Item 8.	Financial Information	73
Item 9.	The Offer and Listing	73
Item 10.	Additional Information	74
Item 11.	Quantitative and Qualitative Disclosures About Market Risk	81
Item 12.	Description of Securities Other than Equity Securities	83

Part II.
Item 13.	Defaults, Dividend Arrearages and Delinquencies	84
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds	84
Item 15.	Controls and Procedures	84
Item 16(A).	Audit Committee Financial Expert	85
Item 16(B).	Code of Ethics	85
Item 16(C).	Principal Accountant Fees and Services	85
Item 16(D).	Exemption from the Listing Standards for Audit Committees	85
Item 16(E).	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	85

Part III.
Item 17.	Financial Statements	86
Item 18.	Financial Statements	86
Item 19.	Exhibits	86

Glossary of Terms
Air drilling	A method of drilling that uses compressed air as a medium for transporting drill cuttings to surface.
Bakken	From the early Carboniferous period, approximately 355 million years of age. This unit consists of fine-grained, deltaic terragenous clastics and organic rich shales (hydrocarbon source rocks) deposited in an extensive embayment present over southern Saskatchewan during this period.
Basal Mannville	A clean quartzose sandstone reservoir containing heavy oil that is present as discrete shoreline trends deposited 105 million years of age in southwestern Saskatchewan. The Basal Mannville is included as a member in the Mannville Group of formations.
Basal Quartz zone	A name generally applied to the Ellerslie formation as it occupies the “bottom” sandstone of the Lower Mannville gas formation of lower Cretaceous Age about 124 millions years of age.
Bbl or Barrel	42 U.S. gallons liquid volume of crude oil or natural gas liquids.
Bcf	Billion cubic feet of gas. Usual expression of proved reserve gas volume.
Belly River formation	Late Cretaceous Age sandstones and shales deposited from 75 to 84 million years ago.
Birdbear	From the late Devonian period, approximately 370 million years of age. This formation consists of mixed carbonates and anhydrites deposited in a restricted shelf and exposed mud-flat environments.
Blairmore formation	Formation encompassing clastic sediments deposited in the Early Cretaceous Age from about 100 to 120 million years ago.
Bluesky formation	Sandstones of the lower Cretaceous Age, about 112 million years old, occurring in Northern Alberta and NE BC.
boe	Barrels of Oil Equivalent. Generally one barrel of oil equals six mcf of gas. Allows reserves of oil and gas to be added together.
boe/d	An expression of barrels of oil equivalent produced per day.
Carbonates	Rocks composed predominantly of Calcium Carbonate (CaCO₃).
Condensate	A mixture comprising pentanes and heavier hydrocarbons recovered as a liquid from field separators, scrubbers or other gathering facilities or at the inlet of a processing plant before the gas is processed.
Cretaceous Age	Rocks from 144 million to 66.4 million years of age.
Crown royalty	An amount payable to the government of the applicable Canadian province in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on Crown lands.
Crude oil	A mixture, consisting mainly of pentanes and heavier hydrocarbons that may contain sulphur compounds, that is liquid at the conditions under which its volume is measured or estimated, but excluding such liquids obtained from the processing of natural gas.
Debolt	From the Mississipian Age, approximately 340 million years old, and is comprised most of shales that are separated by regional disconformities.
Depletion	The reduction in petroleum reserves due to production.
Development or developed	Refers to the phase in which a proven oil or gas field is brought into production by drilling and completing production wells and the wells, in most cases, are connected to a petroleum gathering system.
Devonian Age	Rocks from 408 million to 360 million years of age.
Discovery	The location, learned through drilling of a well, where there exists an accumulation of gas, condensate or oil reserves. The size of the reserves may be estimated but not precisely quantified and may or may not be commercially economic, depending on a number of factors.
Drill stem test	A method of packing off the pressure of drilling mud weight to allow a prospective oil or gas formation to flow into the drill stem pipe. Drill stem test results assist in evaluating the potential of the zone to flow or to be pumped commercially.
Dry hole	A well drilled without finding commercially economic quantities of hydrocarbons.
Ellerlsie zone or formation	A name applied to a group of sandstones that are clear and Quartzose with good porosity and permeability for oil and gas about 124 millions years of age.
Edmonton formation	Fluvio-deltaic sandstones and shales deposited approximately 70 million years ago. The Edmonton formation is a vast East/Southeast -thinning wedge of predominantly non-

	marine sediments deposited along the western to northwestern margin of a subsiding marine seaway that may have stretched from the Artic to the Atlantic to the Gulf of Mexico.
Exploration well	A well drilled in a prospect without knowledge of the underlying sedimentary rock or the contents of the underlying rock.
Farmin	By way of agreement, a party earns (farmin) an interest in lands comprising petroleum and natural gas rights from another party by drilling a well or similar activity that evaluates, explores or develops the lands for the production of petroleum substances.
Farmout	By way of agreement, a party gives up (farmout) an interest in lands comprising petroleum and natural gas rights to another party who earns the interest by drilling a well or similar activity that evaluates, explores or develops the lands for the production of petroleum substances.
Field	An area that is producing, or has been proven to be capable of producing, hydrocarbons.
Field netbacks	Revenues from the sale of all commodities produced, less applicable resource and production royalties, less operating costs.
Formation	A reference to a group of rocks of the same age extending over a substantial area of a basin.
Freehold royalty	An amount payable to a mineral rights holder in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on non-Crown lands.
GAAP	Generally accepted accounting principles.
Geology	The science relating to the history and development of the Earth.
Glauconite	A sand group from the upper Mannville formation (lower Cretaceous Age) about 110 million years ago with a green mineral constituent.
Gross acres	The total acreage in which the Company has an interest.
Hackett formation	A sand package that occurs at the base of the Lower Mannville gas formation (lower Cretaceous Age), 118 to 120 million years old.
Hectare	A land measurement equaling 2.471 acres.
Horizontal well	A vertical well bore that is gradually deviated (usually horizontally to 90⁰) in order to intersect the targeted formation.
Hydrocarbon	The general term for oil, gas, condensate, liquids and other petroleum products.
Jean Marie formation	A patch reef carbonate reservoir within the Upper Devonian Age formation, about 367 to 369 million years old. The Jean Marie is found in NE British Columbia and is the stratigraphic equivalent to the lower Nisku formation in Alberta.
kilometer	A measurement of distance equaling 0.621 miles or 3,281 feet.
Leduc D-3 formation	A reefal carbonate reservoir found within the Upper Devonian Age formation, about 369 to 373 million years old. These ancient Leduc reefs were the initial target for oil and gas exploration in Alberta. Leduc No. 1, approximately 30 km. South of St. Albert, was the discovery well for conventional oil in Western Canada.
Logs	Recordings from electrical and radioactive source devices that are run down wellbores to measure petrophysical properties of the adjacent rock
Lower Mannville gas	Any gas sands found in the lower half of the lower Cretaceous Age zones, about 110 million years old. These sands may comprise the Ostracod, Basal Quartz or Ellerlsie zones.
Mbbl	1,000 barrels of oil and/or natural gas liquids.
mboe	1,000 barrels of oil equivalent. See ‘boe’ for further details.
mcf	1,000 cubic feet of natural gas.
mcf/d	1,000 cubic feet of natural gas production per day. Usually used to express the
mcf/d	production rate of a group of gas wells.
Mannville	From the early Cretaceous period, approximately 110 million years old and represents a major episode of subsidence and sedimentation.
Meter	A physical measurement equaling 3.281 feet.
Mineral taxes (freehold)	An amount levied by the government of Alberta in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on non- government (freehold) lands in Alberta.
Mississipian Age	Rocks from 360 to 325 million years of age.
Mmcf	1,000,000 cubic feet of natural gas.

mmcf/d	1,000,000 cubic feet of natural gas production per day. Usually used to express the production rate of a gas well or group of gas wells.
NYMEX	New York Mercantile Exchange, the largest physical commodity exchange in the world.
Natural gas	The lighter hydrocarbons and associated non-hydrocarbon substances occurring naturally in an underground reservoir, which under atmospheric conditions are essentially a gas, but that may contain liquids.
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.
Net acres	The percentage of gross acreage in which the Company has a working interest.
Nisku D-2 formation	A reefal carbonate reservoir in the Winterburn Group of the upper Devonian Age, about 367 to 369 million years old. The Nisku is found exclusively within Alberta but it is a stratigraphic equivalent to the Jean Marie formation in British Columbia.
Ostracod zone	Rocks from the lower Cretaceous Age approximately 119 million years ago comprised of sandstones and marlstones that contain a small fossil named Ostracod.
Ostracod well	A gas well capable of producing commercially from the lower Cretaceous Age Ostracod zone.
Operator	That party to a joint venture agreement whose responsibility it is to carry out all exploratory, development, maintenance and record-keeping duties on behalf of other joint venture partners in relation to hydrocarbon extraction on the joint-ventured lands.
Overriding royalty	An amount payable to a third party other than Crown or freehold royalties in relation to the production of petroleum, natural gas or related hydrocarbons from an oil or gas well located on lands in which the interest of the third party usually arises out of a separate agreement.
Pentanes	A hydrocarbon by-product of natural gas generally referred to as condensate that is of the paraffin series having a chemical formula of C₅H₁₂and having all its carbon atoms joined in a straight chain.
Permeability	Capacity of a rock for transmitting a fluid.
Permit or licence area	An area that is granted for a prescribed period of time for exploration, development or production under specific contractual or legislative conditions.
Pipeline	A system of interconnected pipes that gather and transport hydrocarbons from a well or field to a processing plant or to a facility that is built to take the hydrocarbons for further transport, such as a gas liquefaction plant.
Proved reserves	Those reserves estimated as recoverable with current technology and under existing economic conditions, from that portion of a reservoir that can be reasonably evaluated as economically productive through analysis of drilling, geological, geophysical and engineering data. This includes the reserves to be obtained by enhanced recovery processes demonstrated to be economically and technically successful in the subject reservoir.
Quartzose	Rocks composed of mostly quartz.
Raw gas	Gaseous effluent from a wellhead or pipeline that is not processed. Contains water vapor, carbon dioxide, nitrogen and possibly hydrogen sulphide (H₂S) gas.
Reservoir rock	Porous limestones, dolomites or sandstones that can trap oil and/or gas in
	interconnected holes, like a sponge.
Royalty	A stated or determinable percentage of the proceeds received from the sale of hydrocarbons calculated as prescribed in applicable legislation or in the agreement with the royalty holder.
Seals	Impermeable barriers to hydrocarbon flow such as shale, lime muds, salt or anhydrite.
Seismic	A geophysical technique using low frequency sound waves to determine the subsurface structure of sedimentary rocks.
Slave Point	From the middle Devonion Age, approximately 375 million years old and is restricted to open-marine carbonate, dominated by shales and argillaceous carbonates.
Sour gas	Raw gas with an amount of hydrogen sulphide (H₂S) gas above pipeline requirements of 10 parts H₂S per million raw gas.
Source rock	Usually shales and clays with a high carbon content deposited in a marine environment.
Sweet gas	Natural gas containing no hydrogen sulphide (H₂S) gas.

Stabilized absolute open flow	The maximum rate of gas production that a wellhead will produce assuming no backpressure when the well is stable.
Tertiary sediment	Soft rock of sands, clays, coals and siltstones from 66.4 to 1.6 million years old.
Triassic Age	Rocks from 245 to 208 million years of age.
Undeveloped	Prior to the time in which a proven oil or gas field is brought into production by drilling and completing production wells.
Vertical well	A well bore that intersects the section(s) containing hydrocarbons at about 90⁰.
Viking	From the middle Cretaceous Age, 98 – 133 Million years old, and is comprised of interbedded, predominatly marine influenced sandstones and shales.
Viking gas well	A well capable of commercial gas production from the upper Cretaceous Age Viking formation sands deposited about 98 million years ago.
Wabamun D-1 formation	Cyclical ramp carbonates deposited approximately 360 – 367 million years ago during the upper Devonian Age period.
Working interest	Those lands in which the Company receives its share acreage of net production revenues.

Part I.

The year covered by this annual report, Fiscal 2004, coincides with the calendar year and is the second full year since we changed our fiscal year-end to December 31 from March 31. Prior to this filing, our most recently filed annual report covered the twelve-month period from January 1, 2003 to December 31, 2003. In this report, we may refer to the 12-month period ending December 31, 2004 as “Fiscal 2004”, the 12-month period ended December 31, 2003 as “Fiscal 2003”, the nine-month period ended December 31, 2002 as “Nine-Month Fiscal Transition 2002”, and the 12-month periods ended March 31, 2002 and 2001 as “Fiscal 2002” and “Fiscal 2001”, respectively. Similarly, in discussion of certain forward-looking information, the 12-month period ended December 31, 2005, may be referred to as “Fiscal 2005”.

Where useful for comparison purposes, we indicated that we annualized our Nine-Month Fiscal Transition 2002 numbers by multiplying the numbers by four-thirds. However, this method does not reflect actual results for the three-month extrapolated period and such results may differ from the outcome achieved by this calculation.

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

Selected Financial Data

The following tables summarize certain of our financial information that is derived from and should be read in conjunction with our Financial Statements and Item 5 – “Operating and Financial Review and Prospects” included elsewhere in this Report. The selected financial data has been prepared in accordance with Canadian Generally Accepted Accounting Principles (Canadian GAAP). The Financial Statements and the notes thereto included pursuant to Item 17 of this Report are also prepared under Canadian GAAP. Included in Note 11 to the Financial Statements is the reconciliation between Canadian GAAP and United States generally accepted accounting principles (U.S. GAAP). Unless otherwise stated in this Report, all references to dollars are in Canadian dollars.

Selected Financial Data Presented According to Canadian GAAP

	As at		As at		As at
	December		December		December
	31		31		31		As at March 31
($000’s)	2004		2003		2002		2002		2001
Balance Sheets
Working capital (deficiency)	(25,513	)	(19,313	)	(16,818	)	(13,281	)	1,969
Total assets	67,692		64,768		44,227		37,732		29,991
Current liabilities	33,982		26,632		23,729		19,625		6,210
Long-term liabilities	2,556		1,588		1,087		1,082		540
Deferred gain on sale	-		-		-		109		340
Future income tax liability	-		5,618		844		-		2,955
Net assets	31,155		30,931		18,568		16,916		19,947
Share capital	39,852		27,747		20,721		20,915		20,642
Retained Earnings (deficit)	(9,455	)	2,825		(2,153	)	(4,025	)	(695	)

				Nine-Month
				Fiscal
	Fiscal		Fiscal	Transition	Fiscal		Fiscal
($ 000’s, except per share data)	2004		2003	2002	2002		2001
Statements of Operations
Gross revenues	40,806		46,848	24,123	26,402		34,463
Gross revenues less net royalties
and production costs	23,262		27,499	13,309	14,215		20,524
Cash flow from operations⁽¹⁾	19,421		23,097	10,810	11,337		18,168
Cash flow per share, basic ($)	0.82		1.08	0.53	0.56		0.91
Cash flow per share, diluted ($)	0.80		1.05	0.53	0.55		0.84
Net (loss) earnings before taxes	(19,716	)	7,189	3,186	(5,259	)	14,449
Net (loss) earnings	(12,281	)	4,978	2,004	(3,412	)	9,714
Common shares – weighted avg. (# 000’s)	23,665		21,394	20,357	20,365		19,938
Common shares – outstanding (# 000’s)	24,559		22,195	20,273	20,462		20,146
Net (loss) earnings per share, basic ($)	(0.52	)	0.23	0.10	(0.17	)	0.49
Net (loss) earnings per share, diluted ($)	(0.52	)	0.23	0.10	(0.17	)	0.48

⁽¹⁾

Cash flow from operations is a non-GAAP measure that does not have standardized meaning as prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other companies. We consider it a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. Below is the determination of the non-GAAP measure by utilizing existing GAAP measures.

				Nine-Month
($000’s)				Fiscal
	Fiscal 2004	Fiscal 2003		Transition 2002		Fiscal 2002	Fiscal 2001
Cash flow from operating activities
(GAAP measure)	15,111	28,294		11,457		9,779	19,264
Changes in non-cash working capital
(GAAP measure)	4,310	(5,197	)	(647	)	1,558	(1,096	)
Cash flow from operations
(non-GAAP measure)	19,421	23,097		10,810		11,337	18,168

Selected Financial Data Presented According to U.S. GAAP

The following tables show the major differences in the application of Canadian GAAP and U.S. GAAP.

			As at	As at
	As at		December	December
	December 31		31	31		As at March 31
($ 000’s)	2004		2003	2002		2002		2001

Balance Sheets
Future income tax asset	-		-	-		371		-
Future income tax liability	-		-	541		-		3,532

Natural gas and oil interests	56,726		56,902	36,236		30,150		21,679
Share capital*	38,725		28,721	21,694		21,883		21,610
(Deficit) retained earnings	(10,949	)	1,331	(3,636	)	(5,422	)	(2,356	)

* For further explanation of the reconciling adjustments shown below, see Note 11 to the Financial Statements presented under Item 17 to this Report.

					Nine-Month
					Fiscal
($ 000’s)	Fiscal		Fiscal		Transition		Fiscal		Fiscal
	2004		2003		2002		2002		2001
Net (loss) earnings under
Canadian GAAP	(12,281	)	4,978		2,004		(3,412	)	9,714
Amortization and depletion	- -		- -		(65	)	(141	)	- -
Accretion of asset retirement
obligation	- -		- -		40		36		- -
Options issued for services	- -		- -		(3	)	- -		(20	)
Write-downs on natural gas and oil
properties	- -		(125	)	(209	)	(141	)	- -
Income taxes	- -		- -		- -		709		(577	)
Net (loss) earnings before cumulative
effect of change in accounting
principle under U.S. GAAP	(12,281	)	4,853		1,767		(2,949	)	9,117
Cumulative effect of change in
accounting principle, net of
applicable taxes	- -		133		- -		- -		- -
Net (loss) earnings under
U.S. GAAP after cumulative effect
of change in accounting principle	(12,281	)	4,986		1,767		(2,949	)	9,117
Net earnings (loss) per common share
under U.S. GAAP, before change in
accounting policy
basic	(0.52	)	0.23		0.09		(0.14	)	0.46
diluted	(0.52	)	0.22		0.09		(0.14	)	0.45
Net (loss) earnings per common share
under U.S. GAAP, after change in
accounting policy
basic	(0.52	)	0.23		0.09		(0.14	)	0.46
diluted	(0.52	)	0.23		0.09		(0.14	)	0.45

Dividends

We have never paid or declared dividends on our shares of Common Stock.

Exchange Rates

Our Financial Statements, as provided under Items 8 and 17 and all dollar amounts presented in this report, are presented in Canadian dollars, unless otherwise expressly stated. For comparison purposes, exchange rates into U.S. dollars are provided. The following tables set forth the exchange rate as of the latest practicable date, high and low exchange rates for the months indicated and the average exchange rates for the reporting periods indicated, based on the noon U.S. dollar buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York (Canadian Dollar = U.S. $1.00) .

Exchange Rates for Canadian Versus U.S. Dollars

The exchange rate as of March 15, 2005 was CDN $1.21 per U.S. $1.00.

Exchange Rates for Canadian Versus U.S. Dollars
(High/low rates for latest six months)	High	Low
February, 2005	1.25	1.23
January, 2005	1.24	1.20
December, 2004	1.24	1.19
November, 2004	1.23	1.18
October, 2004	1.27	1.22
September, 2004	1.31	1.26

Exchange Rates for Canadian Versus U.S. Dollars

	Average ($)
For the twelve-month period ended December 31, 2004	1.30
For the twelve-month period ended December 31, 2003	1.40
For the nine-month period ended December 31, 2002	1.56
For the twelve-month period ended March 31, 2002	1.57
For the twelve month period ended March 31, 2001	1.50

Capitalization and Indebtedness

Not applicable.

Reasons for the Offer and Use of Proceeds

Not applicable.

Risk Factors

Set forth below are risk factors that could materially adversely affect our cash flow from operations, operating results and financial condition.

Exploration and Development Risks

Exploration and development of natural gas and oil involves a high degree of risk that no commercial production will be obtained or that the production will be insufficient to recover drilling and completion costs. The costs of drilling, completing and operating wells is sometimes uncertain, and cost overruns in exploration and development operations can adversely affect the economics of a project. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, joint venture partner and/or operator decisions, equipment failures, weather conditions, marine accidents, fires and explosions, compliance with governmental requirements, and shortages or delays in the delivery of equipment. Furthermore, completion of a well does not ensure a profit on the investment or a recovery of drilling, completion and tie-in costs.

Replacement of Reserves

In general, the rate of production from natural gas and oil properties declines as reserves are depleted. The rate of decline depends on reservoir characteristics and other factors. Except to the extent we acquire properties

containing proved reserves or conduct successful exploration and development activities, or both, our estimated proved reserves will decline as reserves are produced. Our future natural gas and oil production, and therefore cash flow from operations and net earnings, are highly dependent upon our level of success in finding or acquiring additional economically recoverable reserves. The business of exploring for, developing and acquiring reserves is capital intensive. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves could be materially impaired.

Estimating of Reserves and Future Net Cash Flows Risk

Estimating natural gas, natural gas liquids and crude oil reserves, and future net cash flows includes numerous uncertainties, many of which may be beyond our control. Such estimates are essential in our decision-making, as to whether further investment is warranted. These estimates are derived from several factors and assumptions, some of which are:

	•	reservoir characteristics based on variable geological, geophysical and engineering assessments;
	•	future rates of production based on historical draw-down rates;
	•	future net cash flows based on commodity price/quality assumptions, production costs, taxes and investment decisions;
	•	recoverable reserves based on estimated future net cash flows; and
	•	compliance expectations based on assumed federal, provincial and environmental laws and regulations.

Ultimately, actual production rates, reserves recovered, commodity prices, production costs, government regulations or taxation may differ materially from those assumed in earlier reserve estimates. Higher or lower differences could materially impact our production, revenues, production costs, depletion expense, taxes and capital expenditures.

Reserve estimates and net present values reported by us elsewhere in this Report are based on estimated commodity prices and associated production costs that are assumed constant for the life of the reserves. Actual future prices and costs may be materially higher or lower.

We have historically invested a significant portion of our capital budget in drilling exploratory wells in search of unproved oil and gas reserves. We cannot be certain that the exploratory wells we drill will be productive or that we will recover all or any portion of our investments. In order to increase the chances for exploratory success, we often invest in seismic or other geoscience data to assist us in identifying potential drilling objectives. Additionally, the cost of drilling, completing and testing exploratory wells is often uncertain at the time of our initial investment. Depending on complications encountered while drilling, the final cost of the well may significantly exceed that which we originally estimated.

Dependence on One Major Property

During Fiscal 2004 and Fiscal 2003, our core property at St. Albert, Alberta, contributed 69% and 85% of our total production, respectively. While the St. Albert property has developed into 16 separate, mutually-exclusive oil and gas pools stacked in seven productive formations (four natural gas and three crude oil), each pool has its own reserves and future production risk, and thus it is important for us to establish producing fields in other areas. Unless we can successfully drill for or acquire economically viable reserves of natural gas and crude oil in other areas, as our production depletes the reserves at St. Albert, our revenue may be materially adversely affected.

Limited Financial Resources

We expect the combination of cash flow from operations, our bank credit facility, and the proceeds from the private placement that closed in the second quarter of 2004 to support land acquisitions, drilling operations, facilities construction, and general/administration costs in Fiscal 2005. If warranted, we may seek term debt to finance construction of long-life facilities and equity to fuel accelerated, project exploration plans. There can be no assurance that we will be able to raise additional capital in light of factors such as the market demand for our securities, the state of financial markets for independent oil companies (including the markets for debt), oil and gas prices and general market conditions (see Item 4 - "Our Information" and Item 5 – “Operating and Financial Review and Prospects”, for discussions of our Fiscal 2005 Capital Investment Program budget).

We expect to continue using our bank credit facility to supplement our available cash. The amount we may borrow under the credit facility may not exceed a borrowing base determined by the lender based on its projections of our proved reserves, future production, future costs of production, taxes, commodity prices and other factors. We cannot control the assumptions the lender uses to calculate the borrowing base. The lender may, without our consent, adjust the borrowing base at any time. If our borrowings under the credit facility exceed the borrowing base, the lender may require that we repay the excess. If this were to occur, we may have to sell assets or seek financing from other sources. We can make no assurances that we would be successful in selling assets at prices acceptable to us or in arranging substitute financing. For a description of our bank credit facility and its principal terms and conditions, see Item 5 - "Operating and Financial Review and Prospects”, and Note 4 to our Financial Statements.

Commodity Price Fluctuations

Our products, including natural gas, NGL’s and oil, and other hydrocarbon products, are commodities. Because our contracts do not fix a long-term price for the products we purchase or sell, market changes in the price of such products have a direct and immediate effect (whether favorable or adverse) upon our revenues and profitability. Prices for products may be subject to material change in response to relatively minor changes in supply and demand, general economic conditions and other market conditions over which we have no control.

Other conditions affecting our business include the level of domestic oil and gas production, the availability and prices of competing commodities and of alternative energy sources, the availability of local, intraprovincial and interprovincial transportation systems with adequate capacity, the proximity of gas production to gas pipelines and facilities, the availability of pipeline capacity, government regulation, the seasons, the weather and the impact of energy conservation efforts.

Dependence on Key Personnel

Our success depends in large part on the professional efforts and expertise of our President & Chief Executive Officer, Wayne J. Babcock, our Vice President & Chief Operating Officer, Donald K. Umbach, our Vice President of Production, David G. Grohs and our Chief Financial Officer & Corporate Secretary, Michael A. Bardell. While the loss of the services of any of these persons could have a material adverse effect on us, we do not carry key-man life insurance.

Drilling Plans Subject to Change

This Report includes descriptions of our future drilling plans with respect to our prospects. A prospect is a property on which our geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. Our prospects are in various stages of review. Whether or not we ultimately drill a prospect may depend on the following factors: receipt of additional seismic data or reprocessing of existing data; material changes in oil or gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; availability and cost of capital; changes in the estimates of costs to drill or complete wells; our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; decisions of our joint working interest owners and operators; and restrictions imposed by governmental agencies. We will continue to gather data about our prospects, and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all.

Potential Variability in Quarterly Operating Results

Demand for our products will generally increase during the winter because they are often used as heating fuels. The amount of such increased demand will depend to some extent upon the severity of winter. Accordingly, our net operating revenues are likely to increase during winter months, although the amount of increase and its effect on profitability cannot be predicted. Because of the seasonality of our business and continuous fluctuations in the prices of our products, our operating results for any past quarterly period may not necessarily be indicative of results for future periods and there can be no assurance that we will be able to maintain steady levels of profitability on a quarterly or annual basis in the future.

Government Regulation and Environmental Matters

We are subject to various federal and provincial laws and regulations including environmental laws and regulations. We believe that we are in substantial compliance with such laws and regulations; however, such laws and regulations may change in the future in a manner that will increase the burden and cost of compliance. In addition, we could incur significant liability for damages, cleanup costs and penalties in the event of certain discharges into the environment.

Certain laws and governmental regulations may impose liability on us for personal injuries, clean-up costs, environmental damages and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for sudden and accidental environmental damages, but do not maintain insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damage. Accordingly, we may be subject to liability or may be required to cease production from properties in the event of such damages.

The main bodies of regulations that apply to us in the areas in which we have significant field operations are The Oil and Gas Conservation Act of Alberta, The Petroleum and Natural Gas Act of British Columbia and The Oil & Gas Conservation Act and Regulations of Saskatchewan and the Crown Minerals Act of Saskatchewan and Petroleum and Natural Gas Regulations of Saskatchewan.

Competition and Business Risk Management

The natural gas and oil industry is highly competitive. We experience competition in all aspects of our business, including searching for, developing and acquiring reserves, obtaining pipeline and/or facilities processing capacity, leases, licenses and concessions, and obtaining the equipment and labor needed to conduct operations and market natural gas and oil. Our competitors include multinational energy companies, other independent natural gas and oil concerns and individual producers and operators. Because both natural gas and oil are fungible commodities, the principal form of competition with respect to product sales is price competition. Many competitors have financial and other resources substantially greater than those available to us and, accordingly, may be better positioned to acquire and exploit prospects, hire personnel and market production. In addition, many of our larger competitors may be better able to respond to factors such as changes in worldwide natural gas or oil prices, levels of production, the cost and availability of alternative fuels or the application of government regulations. Such factors, which are beyond our control, may affect demand for our natural gas and oil production. We expect a high degree of competition to continue.

Risks Pertaining to Acquisitions and Joint Ventures

Part of our business strategy is to expand through acquisitions and is therefore dependent upon our ability to complete suitable acquisitions and effectively integrate acquired assets into our operations. Suitable acquisitions, on terms acceptable to us, may not be available in the future or may require us to assume certain liabilities, including, without limitation, environmental liabilities, known or unknown.

Shortage of Supplies and Equipment

Our ability to conduct operations in a timely and cost effective manner is subject to the availability of natural gas and crude oil field supplies, rigs, equipment and service crews. Although none are expected currently, any shortage of certain types of supplies and equipment could result in delays in our operations as well as in higher operating and capital costs.

Interruption From Severe Weather

Our operations are conducted principally in the central region of Alberta, the northeastern region of British Columbia, and the southwestern region of Saskatchewan. The weather during colder seasons in these areas can be extreme and can cause interruption or delays in our drilling and construction operations.

Limited Operating History

We commenced operations in 1979. We have one major property that began as a one-well producing property in 1985. By Fiscal 1999, the property became our major producing property with up to twenty-four producing

natural gas and oil wells. Although production history from the majority of wells on the property is beyond five years, proved reserves and future production attributable to this property are somewhat more susceptible to estimation discrepancies than fields with longer production histories.

We first experienced earnings in Fiscal 1999 of $1,211,638. In Fiscal 2000 and Fiscal 2001, we reported earnings of $4,078,577 and $9,714,030 respectively and in Fiscal 2002, we had a loss of $3,412,452. In Nine-Month Fiscal Transition 2002, and in Fiscal 2003 we again reported earnings of $2,004,306 and $4,978,302, respectively. As at December 31, 2003, we had accumulated retained earnings of $2,825,311. In Fiscal 2004, we reported a loss of $12,280,609. As at December 31, 2004, we had accumulated deficit of $9,455,298. Our future viability should be considered in light of the risks and difficulties frequently encountered by companies engaged in the junior stages of oil and gas exploration, development and production activities.

Dependence on Third-Party Pipelines

In Fiscal 2004, substantially all our sales of natural gas were effected through deliveries to local third-party gathering systems to processing plants in Alberta owned by ATCO Midstream Ltd. and Northwestern Utilities Limited. In addition, we rely on access to interprovincial pipelines for the sale and distribution of substantially all of our gas. As a result, a curtailment of our sale of natural gas by pipelines or by third-party gathering systems, an impairment of our ability to transport natural gas on interprovincial pipelines or a material increase in the rates charged to us for the transportation of natural gas by reason of a change in federal or provincial regulations or for any other reason, could have a material adverse effect upon us. In such event, we would have to obtain other transportation arrangements or we would have to construct alternative pipelines. There can be no assurance that we would have economical transportation alternatives or that it would be feasible for us to construct pipelines. In the event such circumstances were to occur, our field netbacks from the affected wells would be suspended until, and if, such circumstances could be resolved.

Availability of Natural Gas Supply

We must connect new wells to our gathering systems, contract for new natural gas supplies with third party pipelines or acquire additional gathering systems in order to maintain or increase throughput levels to offset current annual production volumes. Historically, while certain individual facilities have experienced decreases in dedicated reserves, we have connected new wells and contracted for new supplies with third-party pipelines that more than offset production depletion of our existing wells. Our ability to connect new wells to existing facilities is dependent upon levels of our oil and gas development activity near existing facilities. Significant competition for connections to newly drilled wells exists in every geographic area served by us. Significantcompetition also exists for the acquisition of existing gathering systems. There can be no assurance that we will renew our existing supply contracts or that we will be able to acquire new supplies of natural gas at a rate necessary to offset depletion of wells currently under contract. In the event such circumstances were to occur, our field netbacks would decrease until, and if, such circumstances could be resolved.

Operating Hazards and Uninsured Risks

The oil and gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally pressured formations, adverse weather conditions, governmental and political actions, premature reservoir declines, and environmental hazards such as oil spills, gas leaks and discharges of toxic gases. The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by us could have a material adverse impact on us. We, and the operators of our properties, maintain insurance in accordance with customary industry practices and in amounts that we believe to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on our financial condition.

As our reserves of natural gas, natural gas liquids and crude oil decline, our success at replacing and adding to them is highly reliant on further exploration and development. To the extent we succeed, our operating cash flows and other capital sources may become insufficient so as to impair our ability to re-invest capital.

Restoration, Safety and Environmental Risk

All our operations are in western Canada and, in particular, the western provinces of Alberta, British Columbia, and Saskatchewan. Certain laws and regulations exist that require companies engaged in petroleum activities

to obtain necessary safety and environmental permits to operate. Such legislation may restrict or delay us from conducting operations in certain geographical areas. Further, such laws and regulations may impose liabilities on us for remedial and clean-up costs, personal injuries related to safety and environmental damages, such liabilities collectively referred to by us as “asset retirement obligations”.

To ensure that we provide for future estimated asset retirement obligations, we recognized $0.1 million in our Statement of Operations and Deficit during Fiscal 2004. This, combined with newly-recognized liabilities of $0.9 million, brings our total recognized amount in our Fiscal 2004 Balance Sheet to $2.6 million. We engage independent engineering consultants to assist in assessing our total asset retirement obligations related to removal and clean-up costs. While we cannot predict their ultimate cost, we currently estimate the future cost to clean up all our operating facilities to be $4.7 million.

While our safety and environmental activities have been prudent and have enabled us to operate successfully in managing such risks, there can be no assurance that we will always be successful in protecting ourselves from the impact of all such risks.

Kyoto Protocol Risk

The Kyoto Protocol treaty (Protocol) was established in 1997 to reduce emissions of greenhouse gases (GHG) that are believed to be responsible for increasing the Earth’s surface temperatures and affecting the global climate change. Canada ratified the Protocol in December 2002. Since the implementation of the Protocol, approximately 160 countries have committed to reduce GHG internationally. The Protocol was legally made effective internationally on February 16, 2005 and Canada has committed to meet a 6% reduction of emission over base-year 1990 during the period 2008 to 2012. Canadian government assurances of cost and volume limits suggest that incremental risks and liabilities attributable to addressing Protocol related policies are manageable. While we believe we are a low-emission producer, it is not possible to predict the impact of how Protocol-related issues will ultimately be resolved and to what extent their impact will affect our future unit operating costs and capital expenditures.

Item 4. Our Information

Our History and Development

Dynamic Oil & Gas, Inc. (formerly Dynamic Oil Limited) was incorporated on March 27, 1979 under the Company Act of the Province of British Columbia, Canada (the predeceasor legislation to the Business Corporation Act (British Columbia)).

Our principal executive office is located in rented space at Suite 230, 10991 Shellbridge Way, Richmond, British Columbia V6X 3C6. Our telephone number is (800) 663-8072. Our web address iswww.dynamicoil.com.

Capital Investment Program Over the Past Three Reporting Periods
(Including Exploration Expense Related to Seismic and Unsuccessful Drilling)

In this Report, we changed the method of reporting capital transactions. We now gather capital transactions under the title, “Capital Investment Program” instead of the former title, “Capital Expenditures”. The difference in methods is that Capital Investment Program includes exploration expenses relating to seismic and unsuccessful drilling efforts, whereas Capital Expenditures did not. Seismic and unsuccessful drilling costs comprise the majority of our Exploration expense as reported in our Statements of Operations and Deficit. Capital expenditures are reported on our Balance Sheets. When combined, annual expenditures for capital, and annual expenses for seismic and unsuccessful drilling represent the sum total of our yearly Capital Investment Program. All comparative amounts have been restated accordingly.

Over the past three reporting periods, spending toward our Capital Investment Program aggregated $86.0 million, an amount that is broken down by reporting period and spending classification in the following table:

Capital Investment Program Over Three Reporting Periods⁽¹⁾

			Nine- Month
			Fiscal
			Transition	Three-Fiscal
($000’s)	Fiscal 2004	Fiscal 2003	2002	Period Total
Land acquisitions	4,154	5,103	2,568	11,825
Drilling, completions and
equipping:
Exploratory⁽²⁾	14,819	6,232	5,215	26,266
Development	7,239	10,223	4,256	21,718
Facilities and pipelining	6,730	1,448	780	8,958
Seismic	3,669	2,349	934	6,952
Other	225	308	84	617
Gross overriding royalty
interest acquisition⁽³⁾	-	9,711	-	9,711
Total	36,836	35,374	13,837	86,047

⁽¹⁾	We follow the successful efforts method of accounting, whereby costs of drilling an unsuccessful well are recorded as exploration expense when it becomes known the well did not result in a discovery of proved reserves or where one year has elapsed since the completion of drilling and near- term efforts to establish proved reserves are not foreseeable, intended, or in our control.

⁽²⁾	As at December 31, 2004, exploratory well-drilling costs of $8.7 million remain capitalized on our balance sheet. These costs relate to seven wells. Various projects are planned in Fiscal 2005 to determine if proved reserves can be assigned to each of the wells. The wells are as follows: three at Cypress/Chowade ($4.9 million); two at Orion ($3.4 million); one at Sandgren ($0.3 million); and one at Peavey/Morinville ($0.1 million). Drilling operations were completed on six of the wells in Fiscal 2004 and on the remaining well in Fiscal 2002. The Fiscal 2002 well, at Peavey/Morinville, was assigned proved reserves and is expected to commence production in Fiscal 2005.

⁽³⁾	On July 7, 2003, we repurchased from three of our officers their gross overriding royalty interests for an aggregate of $6.5 million. The aggregate purchase price was paid by the issuance of 1.1 million shares of our common stock and the payment of $1.0 million in cash. The repurchased overriding royalty interest of $9.7 million shown above is comprised of the aggregate repurchase price of $6.5 million paid to the sellers, plus the related future income taxes of $3.2 million, which require recognition in accordance with current accounting rules under Canadian GAAP. (For further details, see Note 6[d] to our Financial Statements under Item 17 to this Report).

In the table above, the total three-year aggregated amount of $86.0 million is itemized further by reporting period as follows:

Fiscal 2004
During Fiscal 2004, our Capital Investment Program expenditures totaled $36.8 million, an amount that was allocated by property and classification as follows:

Capital Investment Program in Fiscal 2004

		Drilling,
		Completions and	Facilities and
($ 000’s)	Land	Equipping	Pipelining	Seismic	Other	Total
Alberta
St. Albert	66	2,758	857	-	-	3,681
Wimborne	16	521	-	-	-	537
Halkirk	-	87	-	-	-	87
Peavey/Morinville	-	118	133	(17)	-	234
Total Alberta	82	3,484	990	(17)	-	4,539
Cypress/Chowade	2,399	8,503	5,429	407	-	16,738
Orion	-	5,314	300	3,195	-	8,809
Total British Columbia	2,399	13,817	5,729	3,602	-	25,547
Saskatchewan
Mantario East	839	3,972	11	34	-	4,856
Flaxcombe	632	235	-	50	-	917
Sandgren	202	550	-	-	-	752
Total Saskatchewan	1,673	4,757	11	84	-	6,525
Other	-	-	-	-	225	225
Total	4,154	22,058	6,730	3,669	225	36,836

Land
During Fiscal 2004, our investment in land increased by $4.2 million, most of which was at Cypress/Chowade ($2.4 million for 4,394 net acres) and at Mantario East and other associated Saskatchewan properties ($1.7 million for 7,502 net acres).

Drilling, Completions, Equipping, Facilities and Pipelining
During Fiscal 2004, expenditures incurred on drilling, completions, equipping, facilities and pipelining totaled $28.8 million. These expenditures were split among Alberta ($4.5 million), British Columbia, ($19.5 million) and Saskatchewan ($4.8 million) and were incurred mainly on the following:

Seismic and Other
Also during Fiscal 2005, we invested $3.7 million on seismic data activity, over 87% of which was for a two-phase, 3D seismic program covering 90 square kilometers on our early-stage exploration property at Orion.

Alberta
St. Albert – We invested $3.6 million on the drilling of two light/medium crude oil wells targeting Leduc D-3, Wabamun D-1, Belly River and Edmonton formations. One of the two wells was successful and is now producing from the Wabamun D-1 formation. The other well was unsuccessful. We completed untested zones in two existing natural gas wells in the Ostracod formation to further optimize sweet gas production. We also optimized our sweet gas compressor and upgraded our salt-water disposal facilities.

Wimborne – Two wells targeting natural gas in the Cretaceous Age formation were drilled for $0.5 million, both of which were unsuccessful.

Halkirk – Surface field equipment for the maintenance of production operations cost $0.1 million.

Peavey/Morinville – We equipped, tied in and began producing from one natural gas well that was drilled in a prior year. Our total investment related to this work was $0.2 million, net of a sale of seismic data.

British Columbia
Cypress/Chowade –During the year, we invested $8.5 million to drill five wells and to complete an untested zone in an existing wellbore. Our working interests in these 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 cased and standing natural gas wells and two were unsuccessful. We also participated in the construction of an 8” 19-kilometer pipeline, most of which was at a 40% working interest.

Orion– We invested $5.6 million to drill four wells targeting gas in the Bluesky, Jean Marie and Slave Point formations. Three of these wells were drilled at 100% working interest and one well was drilled at a 50% working interest. Two of the 100% wells have been cased as potential standing gas wells and the other two wells were unsuccessful..The Slave Point well was cased and production tested but did not produce commercial quantities of gas. The well is a cased and standing gas well with further sidetrack drilling potential. We also invested $3.2 million on a two-phase, 3D seismic program covering 90 square kilometers.

Saskatchewan
Mantario East, Flaxcombe & Sandgren– During the year, we invested approximately $4.8 million at Mantario East, Flaxcombe and Sandgren. In total, we drilled 15 wells, five of which were earning wells drilled at 100% working interest under a farmout agreement and 10 of which were non-earning wells drilled at a 75% working interest with an industry partner. The 15-well drilling program resulted in 11 successful heavy-oil wells in a newly-discovered pool at Mantario East and one cased and standing potential natural gas well at Sandgren. There were two unsuccessful wells at Mantario East and one at Flaxcombe.

Fiscal 2003
During this period, we invested an aggregate of$35.4 million, $12.3 million, or 35%, of which was spent on Alberta properties and $13.0 million, or 37%, on British Columbia properties. The amount invested in Alberta was for land, drilling, completions, equipping and facilities on the following properties: St. Albert - $7.1 million; Wimborne – $3.9 million; Halkirk - $1.1 million; and Peavey/Morinville and Other - $0.2 million. The amount invested in British Columbia was invested on similar expenditures at: Cypress/Chowade - $9.9 million; and Orion - $3.1 million.

Also during Fiscal 2003, we repurchased for $6.5 million (1.1 million of our Common Shares and $1.0 million in cash), certain gross overriding royalty interests (“GORR”) that previously burdened our total current and future corporate production by 3%. The carrying value of the repurchase was adjusted upward by a non-cash amount of $3.2 million, as required by Canadian GAAP. This non-cash adjustment represented a future tax liability that was created due to the total payment being part shares and part cash. The resulting $9.7 million has been allocated to all properties with proved, producing reserves as of July 7, 2003, the effective date of the repurchase. (For further details of the GORR repurchase, see Note 6[d] to our Financial Statements).

Nine-Month Fiscal Transition 2002
During this period, we invested an aggregate of$13.8 million, $7.3 million or 53% of which was spent on Alberta properties and $6.5 million or 47% on British Columbia properties. Of the amount invested in Alberta, $5.4 million was for land, drilling, completions, equipping and facilities at St. Albert, $1.2 million was for drilling, completions and equipping at Halkirk, and the balance of $0.7 million was for a seismic program at Wimborne. Of the amount invested in British Columbia, $5.1 million was for drilling, completions and equipping at Cypress/Chowade and the balance of $1.4 million was for land acquisitions at Orion.

Fiscal 2005 – Budgeted Capital Investment Program

During Fiscal 2005, our budgeted Capital Investment Program totals $21.9 million, an amount that is broken down by spending classification and property in the following table:

Fiscal 2005 – Budgeted Capital Investment Program

		Drilling,		Seismic
	Land	Completions	Facilities and	and
($ 000’s)	Acquisitions	and Equipping	Pipelining	Other	Total
Alberta
St. Albert	-	1,595	675	150	2,420
Halkirk	- -	1,010	- -	- -	1,010
Peavey/Morinville	-	180	-	80	260
Total Alberta	- -	2,785	675	230	3,690
British Columbia	-
Cypress/Chowade	150	2,935	1,895	300	5,280
Orion	-	1,575	-	-	1,575
Total British Columbia	150	4,510	1,895	300	6,855
Saskatchewan
Mantario East and Area	39	7,151	2,531	114	9,835
Total Saskatchewan	39	7,151	2,531	114	9,835
Contingency/Other	- -	- -	- -	1,475	1,475
Total – All Provinces	189	14,446	5,101	2,119	21,855

Our Fiscal 2005 Capital Investment Program budget focuses on three primary objectives:

	•	To continue to optimize production and cash flow from our St. Albert and Mantario East properties. As our primary producing assets, St. Albert and Mantario East are expected to contribute 55% and 26 % of our total 2005 production targets, respectively;
	•	To generate reserve and production growth in 2005 through the development of new drilling opportunities, pipelining and facility projects; and
	•	To establish new core areas for future growth through our exploration efforts at Orion, Cypress/Chowade and in the Mantario East area.

In total, our budget for Fiscal 2005, is allocated 17% to Alberta, 31% to British Columbia, 45% to Saskatchewan, and 7% to properties yet to be allocated between the three provinces.

Our 2005 Capital Investment Program is based on our targeted daily average production rates (see Item 5 – “Outlook for Fiscal 2004”), and estimated weighted average prices for our commodities (see Item 5 – “Liquidity and Capital Resources – Sources and Uses of Cash”). We expect to finance our 2005 Capital Investment Program from operating cash flows, supported by a revolving line of credit with our corporate bank. From time to time, as warranted,

we may seek term debt to finance long-life facilities and equity to fuel accelerated project exploration plans, and we may make amendments to our Capital Investment Program.

Recent Material Events

On February 28, 2005, the Company officially renounced, or “flowed-through” to shareholders, $11,200,000 in taxable benefits pursuant to a flow-through private placement that closed on May 19, 2004 for 2,000,000 shares issued at $5.60 per share. The taxable benefits relate to expenditures made, or to be made, by us, on exploration-only expenses that are specifically defined in the Income Tax Act (Canada). As at December 31, 2004, the Company had incurred approximately 67% of the qualifying expenditures and committed another 20% toward the required obligation. The remainder of the qualifying expenditures must be incurred by December 31, 2005. (See Note 6[a] to our Financial Statements for further details).

Share Repurchases

We did not repurchase any shares in Fiscal 2004 or Fiscal 2003. We spent an aggregate $0.3 million on the repurchase of outstanding common shares in Nine-Month Fiscal Transition 2002. The number of common shares repurchased was approximately 0.2 million at an average purchase price of $1.72 per share.

Business Overview

General

Our principal business is acquiring, exploring and developing natural gas and crude oil properties. Our natural gas and crude oil properties are located in the Canadian provinces of Alberta, British Columbia and Saskatchewan. Over each of the past three years, we have explored for, produced and marketed natural gas, natural gas liquids and crude oil. We intend to continue this type of business activity.

The oil and gas industry deals in two basic forms of ownership interests, namely Working Interests and Overriding Royalties:

	(i)	Working Interest (WI): means the percentage of undivided interest held by a Joint Operator (i.e. leaseholder) in a specific tract of land (i.e. joint lands). The Working Interests held by all Joint Operators in any specific tract of joint lands must total 100%. Each WI party is responsible for its WI percentage share of costs incurred to conduct "work" (i.e. drilling, seismic, production etc.) on the joint lands. Working Interests are always considered to be an active interest in the costs, risks and benefits associated with the joint lands and operations conducted thereon and the oil or gas produced there from.

	(ii)	Overriding Royalties (ORR): Overriding Royalties are a specified share of oil and/or gas as and when produced. ORR's are free and clear of costs, risk and expense to the holder of the ORR. Usually ORR's are based on gross production and as such are referred to as "Gross" Overriding Royalties or GORR's. ORR's are considered a passive interest in as much as the holder of an ORR is not subject to any cost, risk or expense nor is the ORR holder involved in any decision-making with respect to the royalty lands.

The majority of our interests are Working Interests and our Overriding Royalty interests would typically be immaterial.

Concentration of Commodities

We derive our revenue principally from the sale of natural gas, natural gas liquids and crude oil. As a result, our revenues are determined, to a large degree, by prevailing spot prices for natural gas, natural gas liquids and crude oil. The market prices for our commodities are dictated by supply and demand. Accordingly, our cash flow from operations and net earnings are greatly affected by changes in prices for natural gas, natural gas liquids and crude oil. We will experience reduced cash flows and may experience operating losses when prices for natural gas, natural gas liquids and crude oil are low (see Item 5 – “Operating and Financial Review Prospects” and Item 11 - “Quantitative and Qualitative Disclosures About Market Risk”).

Under extreme circumstances, our commodity sales may not generate sufficient revenue to meet our financial obligations and to fund planned capital expenditures. Moreover, significant price decreases could negatively affect our reserves by reducing the quantities of reserves that are recoverable on an economic basis, necessitating write-downs to reflect the realizable value of the reserves in the lower-price environment.

We are unable to control the market prices for natural gas, natural gas liquids and crude oil. Such market prices depend on numerous factors that include:

	•	the extent of domestic production and exportation of natural gas, natural gas liquids and crude oil;
	•	the proximity of pipelines or other economically-feasible transportation;
	•	the availability of pipeline capacity;
	•	the demand for natural gas, natural gas liquids and crude oil by utilities and other end users;
	•	the availability of alternative fuel sources;
	•	the effects of weather variability; and
	•	the effects of regulations on transporting, marketing and exporting natural gas, natural gas liquids and crude oil within Canada.

Because of these and other factors, we may be unable to market all of the natural gas, natural gas liquids and crude oil that we have available for sale. Additionally, we may be unable to obtain favorable prices for the natural gas, natural gas liquids and crude oil that we produce.

Concentration of Operations

Our main producing property is located at St. Albert, Alberta. Of our total production in Fiscal 2004, 69% came from the St. Albert property. The remainder originated mainly from seven other fields: Halkirk, Cypress/Chowade, Peavey/Morinville, Alexander, Stanmore, Westlock and our newest field, Mantario East.

In Fiscal 2003, 85% of our production came from the St. Albert field, while the remainder came from the same fields as above, except that Simonette was shut in during Fiscal 2004 and that Mantario East was not yet discovered.

In Nine-Month Fiscal Transition 2002, 85% of our production came from the St. Albert field, while the remainder came from the same fields as in Fiscal 2003, except that Cypress/Chowade was not yet discovered.

Revenue Breakdown

Our total revenue for the past three reporting periods was $111.8 million. Of this total, 70% came from the sales of natural gas, 15% from the sales of natural gas liquids; 14% from the sales of light/medium crude oil; and 1% from the sales of heavy crude oil.

On a province basis, 96% of our total revenue originated from properties and interests in the Province of Alberta, 3% from the Province of British Columbia and 1% from the Province of Saskatchewan.

The following table shows our natural gas, natural gas liquids, light/medium crude oil and heavy crude oil revenue for each of the past three reporting periods and the cumulative of the three periods.

Natural Gas, Natural Gas Liquids and Crude Oil Revenue

			Nine Month Fiscal	Three-Fiscal
($ 000’s)	Fiscal 2004	Fiscal 2003	Transition 2002	Period Total
Natural gas	30,802	30,649	17,058	78,509
Natural gas liquids	6,333	6,646	4,012	16,991
Light/medium crude oil	3,202	9,553	3,053	15,808
Heavy crude oil	469	-	-	469
Total	40,806	46,848	24,123	111,777

Seasonality and Raw Materials

The seasonality of our main revenue-generating commodity, natural gas, is affected solely by the North American climate. Typically, there are two ‘peak’ seasons and two corresponding ‘shoulder’ seasons for natural gas sales. Winter is generally the higher-demand period due to cold-weather heating requirements. The summer is the next highest period of demand due to hot-weather air conditioning requirements.

Natural gas is becoming increasingly important as an energy source to power natural gas-fired electric power generating facilities (co-gen facilities). We believe that as more co-gen facilities are approved, constructed and put into operation, the demand for natural gas during shoulder seasons will remain relatively strong.

We do not rely on the availability of raw materials, because we operate in an extractive industry.

Marketing

Natural gas -Our natural gas portfolio is split between two primary markets, one is the Alberta Spot Market that trades at the AECO storage hub (www.encanastorage.com), the other is an aggregator pool called ProGas (www.progas.com).

AECO, an intra-Alberta trading hub, offers producers the opportunity to participate in natural gas transactions for terms of one day, one month, summer and winter blocks, and annually. We are currently selling our uncommitted natural gas volumes into the AECO daily spot market; however, our marketing strategy includes securing monthly and term deals, if optimal.

ProGas, a wholly-owned subsidiary of BP Canada, ‘aggregates’ supplies of natural gas to sell into a basket of daily, short term (less than one year) and long-term contracts, both domestic and export. Producers realize a netback price for their natural gas, which is a blend of all contract types weighted toward NYMEX-based prices.

During Fiscal 2004, we sold 40% of our natural gas to Progas and 60% into the AECO daily spot market. During Fiscal 2003, we sold 46% of our natural gas to ProGas and 54% into the AECO daily spot market. During Nine-Month Fiscal Transition 2002, we sold 51% of our natural gas to ProGas, and 49% into the AECO daily spot market.

Since 1997, we committed to sell our future natural gas production from St. Albert through Progas under a life-of-reserves agreement. As other fields have come on stream, we have elected to sell the uncommitted natural gas into the AECO daily spot market. Management believes that this current allocation of our gas production into the two markets provides an optimum balanced portfolio.

Natural gas liquids and crude oil -We market our natural gas liquids, and light/medium crude oil based on monthly prices posted by the major purchasers at Edmonton, Alberta. Our heavy crude oil is marketed based on monthly prices posted at Hardisty, Saskatchewan. The trends in these posted prices tends to correlate with the West Texas Intermediate benchmark price, allowing for quality adjustments and transportation differentials.

Supply Contracts or Agreements

Under various supply contracts and agreements, the commitment period under which we are required to supply natural gas and natural gas liquids ranges from terminable upon thirty days notice to no termination prior to exhaustion of hydrocarbon reserves. Under these various contracts and agreements, we are not obligated to provide a fixed quantity of supply, as all supply is on a best-efforts basis.

Competition

We regularly compete with other companies in bidding for the acquisition of petroleum interests from the Alberta, British Columbia, and Saskatchewan governments and other corporations or individuals holding such interests. Further, we regularly compete for the availability of drilling rigs, production equipment, processing facilities, pipeline capacity and other transportation services. We do not have a competitive position that allows us any material or significant advantages compared to other companies within the same industry. Many competitors have substantially greater financial and other resources than we do. For example, according to Pricewaterhouse Cooper’s 2004 Canadian Energy Survey of 2003 Results, our gross revenues and cash flow from operations would have ranked us twenty-ninth and thirty-first, respectively, out of the top one hundred.

Governmental Regulations

Government regulations have a material effect on us to the extent that they require us to conduct field operations and hydrocarbon extraction activities according to prescribed environmentally-safe, sensitive regulations. Also, government regulations may restrict the commencement or re-commencement of field activities in certain properties in which we hold an interest for the purpose of exploration. Examples of types of governmental laws and regulations that may have a material effect on our business include:

•	requirements to acquire permits before commencing drilling operations;
•	requirements to restrict the substances that can be released into the environment in connection with drilling and production activities;
•	limitations on, or prohibitions to, drilling in protected areas such as offshore areas; and
•	requirements to mitigate and remediate the effects caused by drilling and production operations.

Properties, Plant and Equipment

We own various 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:

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			Sandgren

Our total land holdings increased during Fiscal 2004 by 8,826 net acres (22,269 gross), or 7%. Of this increase, 85% was due to newly-acquired interests in three new properties in Southern Saskatchewan: Mantario East; Flaxcombe; and Sandgren. The remaining 15% was the net result of new acquisitions at Cypress/Chowade and Orion, and minor land reductions at St. Albert and Peavey/Morinville. Our total land holdings were 130,747 net acres, of which 101,878 net acres, or 78%, were undeveloped.

Land Holdings (acres)
As at December 31, 2004

	Developed		Undeveloped		Total		Weighted
Area	Gross	Net	Gross	Net	Gross	Net	Avg WI %
Alberta
St. Albert	8,901	5,873	3,938	2,228	12,839	8,101	63%
Halkirk	3,840	3,456	2,880	2,880	6,720	6,336	94%
Peavey/Morinville	6,467	4,708	3,776	2,290	10,243	6,998	68%
Wimborne	2,560	1,760	7,115	5,995	9,675	7,755	80%
Other	3,527	2,690	9,920	6,352	13,447	9,042	67%
	25,295	18,487	27,629	19,745	52,924	38,232	72%
British Columbia
Cypress/Chowade	10,978	4,925	45,697	14,986	56,675	19,911	35%
Orion	5,340	4,005	61,274	42,797	66,614	46,802	70%
Fraser Valley	-	-	54,502	18,278	54,502	18,278	34%
	16,318	8,930	161,473	76,061	177,791	84,991	48%
Saskatchewan
Mantario East	967	745	2,928	2,206	3,895	2,951	76%
Flaxcombe	40	30	6,085	3,153	6,125	3,183	52%
Sandgren	680	655	1,903	713	2,583	1,368	53%
Rapdan	160	14	-	-	160	14	9%
Elmore	162	8	-	-	162	8	5%
	2,009	1,452	10,916	6,072	12,925	7,524	58%
Total to Dec 31, 2004	43,622	28,869	200,018	101,878	243,640	130,747	54%
Total to Dec 31, 2003	32,081	21,665	189,290	100,256	221,371	121,921	55%
Increase (decrease)	11,541	7,204	10,728	1,622	22,269	8,826
Increase (decrease) %	36%	33%	6%	1.6%	10%	7%

Our weighted average working interests in our properties were: Alberta - 72%, British Columbia – 48%; and Saskatchewan – 58%. Our total weighted average working interest in Fiscal 2004 was 54% compared to 55% in Fiscal 2003.

Alberta Properties

St.Albert
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 completed untested zones in 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.

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
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.

Wimborne
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 cased and 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.

British Columbia Properties

Cypress/Chowade
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 cased and standing natural gas wells. In the four producing wells, we own a 50% working interest. Our working interests in the six cased and 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 pipeline 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 in completing 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 cased and standing 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 was 30% in two of these wells and 50% in the third.

Fiscal 2005 Outlook
We plan to participate, at a 30% working interest, in drilling two exploratory outpost wells and shooting 15 kilometers of 2D seismic. We also plan to have two of our six cased and 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.

Orion
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 cased and standing potential Jean Marie gas well and a 100% working interest in one cased and standing potential Bluesky formation gas well. The gross overriding royalty interest will convert to a 50% working interest after payout. Both wells are cased and 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 data 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 cased as a potential standing 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 cased and 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-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.

Fraser Valley
The property is located in the Lower Mainland area of southwest British 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
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.

S.W. Saskatchewan Properties

Mantario East and Surrounding Areas
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 7,524 net acres (12,925 gross) for a weighted average working interest of 58%. Approximately 81% of our net holdings are undeveloped.

Well and Facilities
We have 11 heavy-oil wells at Mantario East, five of which are in production and six of which are cased and 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 other two producing and the six cased and 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 quarters of Fiscal 2004. Of these, five were earning wells drilled at a 100% working interest under a farmout agreement and 10 were non-earning wells drilled at a 75% working interest with an industry partner. The 15-well drilling program resulted in five producing, and 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 to conduct a 15-well, in-fill drilling program targeting Basal Mannville oil. We also have budgeted to build a gathering system and a heavy crude oil battery facility in Fiscal 2005. We also plan to equip and tie-in two of six cased and standing heavy crude 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 data in the area.

The gathering system and heavy crude 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 heavy crude oil wells to a central battery facility capable of processing up to 1,500 barrels per day. Phase II will include tie-in of remaining wells as they are drilled and will expand the 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.

Estimated Reserves of Crude Oil, Natural Gas and Natural Gas Liquids

As a Canadian issuer, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities”(NI 51-101) issued by the Canadian Securities Administrators, in all of our reserves related disclosures. NI 51-101 was effective September 30, 2003 and applies to financial years ended

on or after December 31, 2003. NI 51-101 mandates significant changes in the way reporting issuers are required to determine and publicly disclose information relating to oil and gas reserves.

Under NI 51-101, proved reservesis an estimate, the premise of which means there must be at least a ninety percent probability that actual quantities of crude oil and natural gas proved reserves recovered will equal or exceed the estimated proved reserves.

The purpose of NI 51-101 is to enhance the quality, consistency, timeliness and comparability of crude oil and natural gas activities by reporting issuers and elevate reserves reporting to a higher level of confidence and accountability.

In the United States, registrants, including foreign private issuers like us, are required to disclose proved reserves using the standards contained in the United States Securities and Exchange Commission (“SEC”) Regulation S-X. However, under certain circumstances, applicable U.S. law permits us to comply with our own country’s law if the requirements vary. We believe that the standards for determining proved reserves under NI 51-101 meet or exceed those set forth under U.S. law and thus we have presented our proved reserves under NI 51-101 only.

The crude oil and natural gas industry commonly applies a conversion factor to production and estimated proved reserve volumes of natural gas in order to determine an “all commodity equivalency” referred to as barrels of oil equivalent (“boe”). The conversion factor we have applied in this Report is the current convention used by many oil and gas companies, where six thousand cubic feet (“mcf”) is equal to one barrel (“bbl”). A boe is based on an energy equivalency conversion method primarily applicable at the burner tip. It may not represent equivalency at the wellhead and may be misleading if used in isolation.

The estimate of our proved reserves on a constant-pricing basis, and their associated net present values, have been based on posted commodity prices on December 31, 2004 as determined by our independent engineering evaluators, Sproule Associates Limited (“Sproule”). These prices have been adjusted for applicable quality and transportation differentials to reflect actual historical prices received by us from each of our properties. Adjusted prices and our associated operating costs incurred have been assumed to remain constant over the life of the reserves. The following table shows the base prices used in the estimate:

Summary of December 31, 2004 Base Prices Used in the Estimate of Reserves on a Constant-Pricing Basis

Indices/By-Products	Natural Gas	Natural Gas Liquids	Light/Medium Oil	Heavy Oil
Alberta AECO-C	$6.78/MMBtu⁽¹⁾
B.C. Westcoast Station 2	$6.68/MMBtu⁽¹⁾
Propane		$36.11/bbl
Butanes		$39.78/bbl
Pentanes Plus		$51.80/bbl
Edmonton Par			$46.51/bbl
Hardisty Heavy, 12^oAPI				$15.26/bbl

⁽¹⁾The weighted average natural gas price expressed on an “mcf” basis was $6.92/mcf.

The reserve data set out in the summary table below is based on Sproule’s engineering evaluation of our estimated proved oil and gas reserves effective December 31, 2004. This evaluation was prepared in accordance with the definitions under NI 51-101, except as noted. Comparative numbers effective December 31, 2003 and 2002 are also shown.

Summary of Company Interest Estimated Reserves (After Royalties)

		Natural Gas	Light and
	Natural Gas⁽¹⁾	Liquids	Medium Oil	Heavy Oil	Total⁽¹⁾
	(mmcf)	(mbbl)	(mbbl)	(mbbl)	(mboe)
Proved
Developed producing	11,859	689	173	248	3,086
Developed non-producing	528	5	11	68	172
Undeveloped	874	10	20	198	374
Total proved – December 31, 2004	13,261	704	204	514	3,632
Total proved – December 31, 2003	19,553	813	407	4	4,483
Total proved – December 31, 2002⁽²⁾	24,781	1,170	997	2	6,299

⁽¹⁾	Estimates of reserves of natural gas includes solution gas.
⁽²⁾	Estimates prepared in accordance with National Policy No. 2-B as stated in the “Consolidated Ontario Securities Act and Regulation 1994”.

Estimated Reserves Reconciliation

The following reconciliation shows the changes in our estimated reserves after royalties that occurred during Fiscal 2004:

Reconciliation of Company Interest Proved Reserves (After Royalties)

			Natural Gas		Light and
	Natural Gas⁽¹⁾		Liquids		Medium Oil		Heavy Oil		Total⁽¹⁾
	(mmcf)		(mbbl)		(mbbl)		(mbbl)		(mboe)
December 31, 2003	19,553		813		407		4		4,483
Acquisitions	7		-		-		105		106
Extensions	128		4		30		-		55
Discoveries	187		-		-		438		469
Improved Recovery	1,170		74		41		-		310
Revisions	(4,348	)	(17	)	(216	)	(16	)	(973	)
Production	(3,436	)	(170	)	(58	)	(17	)	(818	)
December 31, 2004	13,261		704		204		514		3,632

⁽¹⁾Estimates of reserves of natural gas includes solution gas.

Net Present Values of Reserves

In the following two tables, we present Sproule’s estimated net present values effective December 31, 2004. Comparative numbers effective December 31, 2003 and 2002 are also provided. The undiscounted and discounted net present values presented may not represent the fair market values of our reserves, as the use of other assumptions could give rise to different results.

Net Present Value of Company Interest Estimated Reserves (After Royalties)

($000’s)	Before Income Taxes		After Income Taxes
	Discount Rate		Discount Rate
	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 – December 31, 2004	80,305	60,587	69,946	52,645
Total proved – December 31, 2003	121,046	87,943	91,023	64,397
Total proved – December 31, 2002⁽¹⁾	164,745	109,651	Not available	Not available

⁽¹⁾Estimates prepared in accordance with National Policy No. 2-B as stated in the “Consolidated Ontario Securities Act and Regulation 1994”.

In accordance with SEC regulations, the above disclosure of our reserve information is on an after-royalties basis. As our production is on a before-royalties basis consistent with other Canadian oil and gas companies, we also disclose in the following tables, a summary and a reconciliation of our estimated proved reserves compliant with NI 51-101 on a before-royalties basis under constant price and operating cost assumptions, except as noted:

Summary of Company Interest Estimated Reserves (Before Royalties)

		Natural Gas	Light and
	Natural Gas⁽¹⁾	Liquids	Medium Oil	Heavy Oil	Total⁽¹⁾
	(mmcf)	(mbbl)	(mbbl)	(mbbl)	(mboe)
Proved
Developed producing	14,300	835	205	314	3,738
Developed non-producing	672	7	13	83	215
Undeveloped	1,165	11	23	223	451
Total proved – December 31, 2004	16,137	853	241	620	4,404
Total proved – December 31, 2003	24,493	987	498	5	5,572
Total proved – December 31, 2002⁽²⁾	31,782	1,483	1,403	3	8,185

⁽¹⁾	Estimates of reserves of natural gas includes solution gas.

⁽²⁾	Evaluation prepared in accordance with National Policy No. 2-B as stated in the “Consolidated Ontario Securities Act and Regulation 1994”.

Reconciliation of Company Interest Proved Reserves (Before Royalties)

		Natural Gas	Light and
	Natural Gas⁽¹⁾	Liquids	Medium Oil	Heavy Oil	Total⁽¹⁾
	(mmcf)	(mbbl)	(mbbl)	(mbbl)	(mboe)
December 31, 2003	24,493	987	498	5	5,572
Acquisitions	9	-	-	133	135
Extensions	146	5	36	-	65
Discoveries	220	-	-	535	571
Improved Recovery	1,369	90	49	-	367
Revisions	(5,519)	(20)	(278)	(31)	(1,247)
Production	(4,581)	(209)	(64)	(22)	(1,059)
December 31, 2004	16,137	853	241	620	4,404

⁽¹⁾Estimates of reserves of natural gas includes solution gas.

On the next several pages, maps show the locations of our various properties that are detailed above.

Item 5. Operating and Financial Review and Prospects

Forward-Looking Information and Safe Harbor Statement under the Private Securities Litigation Reform Act of 1995.

Certain statements in this Report, including those appearing under this Item 5, constitute “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as amended. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us on our behalf. Such statements are generally identifiable by the terminology used such as “plans”, “expects, “estimates”, “budgets”, “intends”, anticipates”, “believes”, “projects”, “indicates”, “targets”, “objective”, “could”, “may” or other similar words.

�� The forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: market prices for natural gas, natural gas liquids and oil products; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdown; actions by governmental authorities including increases in taxes, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; and the other factors discussed in Item 3 Key Information – “Risk Factors”, and in other documents that we file with the United States Securities and Exchange Commission. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors; our course of action would depend upon our assessment of the future considering all information then available. In that regard, any statements as to future natural gas, natural gas liquids or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas, natural gas liquids and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectibility of receivables; availability of trade credit; expected operating costs; expenditures and allowances relating to environmental matters; debt levels; and changes in any of the foregoing are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge

from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

Operating Results

Summary

During Fiscal 2004, we operated or participated in a corporate drilling record of 28 new wells. The results of this drilling activity were as follows: heavy crude oil wells - five producing, and six cased and standing; light/medium crude oil wells – one producing; natural gas wells – six cased and standing; and unsuccessful wells - ten. Of the 18 wells drilled that were either producing or cased and standing, we had one exploratory well and two development wells at Cypress, two exploration wells at Orion, one development well at St. Albert, and five exploration wells and seven development wells in the Mantario East area.

Results of Drilling Activity

					Nine-Month
	Fiscal 2004		Fiscal 2003		Fiscal Transition 2002
	Gross	Net WI	Gross	Net WI	Gross	Net WI
Natural gas:
Producing	-	-	7	4.3	1	0.8
Cased and standing	6	4.8	1	1.0	6	3.5
Heavy oil:
Producing	5	4.9	-	-	-	-
Cased and standing	6	4.5	-	-	-	-
Light/medium crude oil:
Producing	1	0.7	4	3.0	2	1.5
Unsuccessful	10	7.1	2	2.0	-	-
Total	28	22.0	14	10.3	9	5.8
% of producing,
cased and standing		68%		80%		100%

Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following should be read in conjunction with our Financial Statements and the Notes to the Financial Statements included in this Report. The Financial Statements have been prepared in accordance with Canadian GAAP. The reconciliation between Canadian GAAP and U.S. GAAP is contained in Note 11 to our Financial Statements.

Unless otherwise noted, tabular amounts are in thousands of Canadian dollars, and production volumes and reserves are before royalties. We have presented our working interest before royalties, as we measure our performance on this basis, which is consistent with other Canadian oil and gas companies.

Due to the differing lengths of the reporting periods in this discussion and analysis, results in these periods are not comparable. Accordingly, percentage changes in these results are not meaningful. In the tables in this discussion and analysis, these are indicated as “n/m”.

Where useful for comparison purposes, annualized numbers relating to Nine-Month Fiscal Transition 2002 are presented by multiplying the nine-month numbers by four-thirds. This method, however, does not reflect actual results for the applicable extrapolated period and as such differs from the actual results.

Throughout this discussion and analysis, we analyze expense factors on a unit cost of production basis. It is industry practice among our peer-group to monitor trends in expenses against daily average production volumes and the common unit of production used is the barrel of oil equivalent (“boe”). We do not analyze expense trends based on gross revenues, as commodity price volatility may lead to less reliable trending results.

Executive Overview

Key Measures for the Comparative Periods Presented

			Nine-Month
			Fiscal
($ 000’s unless otherwise stated)	Fiscal 2004	Fiscal 2003	Transition 2002
Gross revenues	40,806	46,848	24,123
Cash flow from operations⁽¹⁾	19,421	23,097	10,810
Cash flow from operations per share($/share )⁽¹⁾	0.82	1.08	0.53
Net (loss) earnings	(12,281)	4,978	2,004
Net (loss) earnings per share($/share)	(0.52)	0.23	0.10

Daily average production(boe/d)	2,893	3,447	3,332
Total production(mboe)	1,059	1,258	916

Capital investment program⁽²⁾	36,836	35,374	13,837
Net debt⁽³⁾	25,513	19,313	16,818
Net debt to cash flow (times)⁽⁴⁾	1.3:1	0.8:1	1.6:1
Net debt to cash flow annualized(times)⁽⁵⁾	1.3:1	0.8:1	1.2:1

⁽¹⁾

Cash flow from operations is a non-GAAP measure that does not have standardized meaning as prescribed by GAAP and therefore may or may not be comparable to similar measures presented by other companies. We consider it a key measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The following table shows how we derive our non-GAAP measure from GAAP measures.

			Nine-Month Fiscal
			Transition 2002
($000’s)	Fiscal 2004	Fiscal 2003
Cash provided by operating activities (GAAP)	15,111	28,294	11,457
Changes in non-cash working capital affecting
operating (GAAP)	4,310	(5,197)	(647)
Cash flow from operations (non-GAAP)	19,421	23,097	10,810

⁽²⁾	For Fiscal 2004, we changed the method of reporting capital transactions. We now report capital transactions under the title, “Capital Investment Program” instead of the former title, “Capital Expenditures”. The difference in methods is that Capital Investment Program includes exploration expenses relating to seismic and unsuccessful drilling efforts, whereas Capital Expenditures did not. Seismic and unsuccessful drilling costs comprise the majority of our Exploration expense as reported in our Statements of Operations and Deficit. Capital expenditures are reported on our Balance Sheets. When combined, annual expenditures for capital, and annual expenses for seismic and unsuccessful drilling, represent the sum total of our yearly Capital Investment Program. All comparative amounts have been restated accordingly.

⁽³⁾	Net debt is working capital. We have no long-term debt.

⁽⁴⁾	Net debt divided by cash flow from operations.

⁽⁵⁾	Net debt divided by cash flow from operations annualized.

Record-high weighted average prices received for natural gas of $6.67 per mcf and light/medium crude oil of $50.03 per barrel led the way in ranking our Fiscal 2004 gross revenues and cash flow from operations as second-highest in our corporate history, behind Fiscal 2003. Gross revenues in Fiscal 2004 were $40.8 million compared to $46.8 million in Fiscal 2003 and cash flow from operations was $19.4 million compared to $23.1 million, respectively. The effect of our weighted average prices is the first key performance measure that impacts our gross revenue, cash flow from operations and ultimately net earnings. Their record-high impact in Fiscal 2004 increased gross revenues over Fiscal 2003 by $2.7 million.

After accounting for price variances, which are largely controlled by the market forces of supply/demand for our commodities, the second key performance measure that impacts us is the variance in our levels of production between periods. Our Fiscal 2004 production levels were 16% below those for Fiscal 2003, which decreased gross revenues by $8.7 million. Total production in Fiscal 2004 was 1,059 mboe and total daily average production was 2,893 boe per day, compared to 1,258 mboe and 3,447 boe per day, respectively, in Fiscal 2003.

Of the decrease in gross revenues attributed to volume changes between Fiscals 2004 and 2003, over 90% was due to production decreases in light/medium crude oil. Most of these decreases related to relatively sharp production declines in two St. Albert wells, both of which reached payout of our original capital expenditures within a few weeks after first coming into production in early Fiscal 2003. Volume changes that contributed to the remaining

decrease in gross revenues were the net result of production decreases in natural gas liquids and production increases in heavy crude oil.

In October 2004, we made a new-pool discovery of heavy crude oil at Mantario East. After drilling our discovery well, we followed up with an aggressive drilling program and by the year-end, we had drilled 13 wells, resulting in five producing, six cased and standing and two unsuccessful wells. Heavy crude oil production commencing in the last two months of Fiscal 2004 increased gross revenues by $0.5 million.

During Fiscal 2004, $0.9 million of our gross revenues decrease was due to declining production of liquid-rich natural gas. Our liquid-rich natural gas originates from our St. Albert field, where we are experiencing a predictable rate of natural decline.

While volumes of liquid-rich natural gas declined at St. Albert during Fiscal 2004, new volumes of lean natural gas came into production at Cypress/Chowade due to the start-up of three new wells. The impact of these increases and decreases in natural gas volumes was a net decrease in our gross revenues of $0.4 million.

After accounting for the two key performance measures discussed above - price and volume variances - cash flow from operations decreased by $1.9 million due to an increase in our cost of production. On a per boe basis, unit production costs may differ according to product-type, field location and age of field. As an example, in Fiscal 2004, unit production costs increased by 52% to $8.44 per boe. Approximately half of the increase was due to remoteness associated with new natural gas production in northeast British Columbia, where time is needed to build economies of scale. The other half of the increase is mainly due to additional variable costs associated with compression fees, and the general effect caused by coverage of fixed costs by declining production from our Alberta fields.

Our net loss in Fiscal 2004 of $12.3 million was contributed to in a significant way by the third key performance measure - the degree of our success in establishing or replacing proved reserves. The costs of unsuccessful drilling efforts and downward revision to proved reserves are reflected in two expense categories – exploration expenses, and amortization and depletion expense.

Exploration expenses increased in Fiscal 2004 by $10.3 million over Fiscal 2003, contributing significantly to our net loss. Our strategies have consistently been to grow proved reserves primarily through drilling and specific, targeted acquisitions. Accordingly, in Fiscal 2004, we participated in drilling a corporate record-high of 28 wells, ten of which were unsuccessful, compared to 14 wells in Fiscal 2003, two of which were unsuccessful. This difference, combined with failed efforts to establish proved reserves in five other wells that were drilled prior to Fiscal 2004 explains most of the increase in our exploration expenses.

Amortization and depletion expense was another significant contributor to our net loss. It increased in Fiscal 2004 by $12.2 million, 88% of which was mainly due to a decrease in proved producing reserves at Cypress/Chowade. The balance was due to higher capital-to-reserve ratios in connection with most of our Alberta properties, increased amortization for leaseholds acquired during Fiscal 2004, and new depletion associated with our Mantario East assets.

While we do not consider income taxes as a key performance measure, they did impact our bottom-line results significantly in Fiscal 2004. Consistent with our pre-tax loss of $19.7 million, our total current and future income taxes changed from an expense of $2.2 million in Fiscal 2003 to a recovery of $7.4 million in Fiscal 2004. After accounting for certain reconciling items, the effective rate of our income tax recovery was 37.7% .

As mentioned above, one of our growth strategies is to target specific acquisitions that we believe will lead to future increases in reserves and prospects for exploration and development. In Fiscal 2004, we acquired an additional 25% working interest in our new-pool heavy crude oil producing property, bringing our working interest to approximately 76% in Mantario East and other associated lands. In Fiscal 2005 we intend to continue this strategy with a focus on lower-risk, lower-cost projects, such as development and production enhancement opportunities.

Effective December 31, 2004, our proved reserves on an after-royalties, constant-price basis were independently estimated at 3,632 mboe, as compared with 4,483 mboe last year. This is a net decrease of 851 mboe or 19%, comprised of total additions to proved reserves of 940 mboe, less production of 818 mboe, and less technical revisions and economic factors of 973 mboe.

The total proved reserve additions of 940 mboe during Fiscal 2004 were made up of 365 mboe added through extensions and improved recovery, 469 mboe added through discoveries, and 106 mboe added through acquisitions. These total additions represented a 15% growth over our production of 818 mboe, before consideration of technical revisions.

The decrease in proved reserves of 973 mboe due to technical revisions and economic factors, were primarily associated with our Cypress/Chowade field. Cypress revisions were effected by a combination of higher-than-expected decline rates from four producing wells and lower reserve expectations in two, recently drilled development wells.

Cypress is an early-stage exploration area and our land base is significant, totaling 56,675 gross acres (19,911 net). Initial drilling results were highly favourable, with the first five wells being classified as new-pool discoveries. Recent results, including our two latest wells, have been much less favourable. Of our total gross acreage at Cypress, 81% is as-yet undeveloped

Also included in technical revisions to our proved natural gas reserves was a decrease of approximately 469 mmcf due to third-party, acid-gas contamination of a single Ostracod sweet gas well at St. Albert that, since March 1, 2004, was no longer able to produce into existing facilities. In early 2005, we expect to receive full cash value for the loss of reserves and production associated with this well.

Extensions, discoveries and improved recoveries increased our estimated proved reserves of natural gas and natural gas liquids by 1,485 mmcf and 78 mbbls, respectively. The majority of this was due to our success with various optimization projects that were designed to mitigate natural production declines at St. Albert.

At St. Albert, an increase of 71 mbbls to estimated light/medium crude oil proved reserves was mainly due to extensions and improved recovery, while a decrease of 216 mbbls was mainly due to revisions. The revisions were largely based upon disappointing drilling results in the Wabamun and Leduc formations. One or two drill targets that could recover a portion of the revisions are being considered for Fiscal 2005.

Estimated proved reserves of heavy oil increased by 510 mbbl due mainly to the discovery of a new oil pool (438 mbbls) and subsequent acquisition of a partner’s interest (105 mbbls) at Mantario East in southwestern Saskatchewan. We operate and own a 76% weighted average interest in 2,951 net acres (3,895 gross) in the Mantario East area.

We incurred $36.8 million on our Fiscal 2004 Capital Investment Program and advanced our strategies in the following ways:

	•	We spent $4.2 million on the acquisition of new lands, over half of which was spent in the Cypress/Chowade area. Most of the remainder was spent at Mantario East and on other associated Saskatchewan properties;

	•	We drilled and completed 28 wells (22.0 net) and equipped most of them for a total cost of $22.1 million. Our overall net working interest drilling success rate was 68%. Of twelve wells that targeted natural gas, six were unsuccessful. The other six, three at Cypress/Chowade, two at Orion and one at Sandgren, were completed as cased and standing wells. We drilled two wells that targeted light/medium crude oil at St.Albert, one of which was successful. The remaining 14 wells targeted heavy crude oil at Mantario East and Flaxcombe, 11 of which were either producing or cased and standing as at December 31, 2004. Three were unsuccessful;

	•	Our investment in facilities, pipelining and other assets grew by $6.7 million. Over 85% of this amount was invested in northeast B.C., most of which was for our participation in the construction of an 8”, 19 kilometer pipeline at Cypress/Chowade. The remaining 15% was primarily for the optimization and upgrading of certain production facilities at St. Albert; and

	•	We invested $3.7 million on seismic data activity, over 87% of which was for a two-phase, 3D seismic program covering 90 square kilometers on our early-stage exploration property at Orion.

In order to finance our Capital Investment Program described above, we took certain measures in Fiscal 2004 to expand our liquidity and capital resources. Mid-year, we completed a private placement resulting in cash proceeds,

net of fees and financing costs, of approximately $11.6 million. Upon closing, we issued 2,000,000 flow-through shares at $5.60 per share and 280,000 common shares (non-flow-through) at $4.55 per share.

The gross proceeds of the flow-through portion of the private placement were $11.2 million, all of which must be spent by December 31, 2005 on qualifying expenses for exploration-only activities that are specifically defined in the Income Tax Act (Canada). As at December 31, 2004, we had incurred approximately 67% and committed another 20% toward the required obligation. In Fiscal 2005, we will be renouncing the tax benefits of the exploration expenses in favour of the flow-through shareholders, in an amount equal to the gross proceeds. Net proceeds of the non-flow-through portion of the financing were earmarked for general working capital.

After accounting for the spending on our Capital Investment Program, the private placement measures discussed above, strong cash flows and $0.2 million from option exercises, our year-end net debt-to-cash-flow ratio was 1.3:1 compared to 0.8:1 last year.

Our planned strategy for Fiscal 2005 is to take a more conservative approach to our exploration program while we develop our new pool discovery at Mantario East and enhance production at St. Albert. We have budgeted to invest approximately $21.9 million toward our Capital Investment Program. The allocation of this budget shifts our focus in Fiscal 2005 proportionately away from higher-risk exploration targets towards other more conservative ways of enhancing shareholder value.

We will also continue to focus on our secondary strategy, which is to target specific acquisitions that we believe will lead to higher returns and future prospects for exploration and development.

We are targeting a 10% year-over-year growth in daily average production in Fiscal 2005, subject mostly to timing issues, equipment availability and adequate funding. Our daily average production levels have a direct impact on our cash flow from operations. If warranted, we may seek term debt to re-finance certain assets and equity to fuel accelerated project exploration or acquisition opportunities. In the event commodities prices increase or decrease materially, we may choose to expand or contract our spending plans. Based on our production targets, our forecasts of strong commodity prices, and support from our bank loan facility, we expect to have adequate resources to meet our Fiscal 2005 cash requirements.

Financial Results

Cash Flow from Operations and Net (Loss) Earnings

Fiscal 2004 vs Fiscal 2003
Cash flow from operations was $19.4 million versus $23.1 million, a decrease between periods of $3.7 million or 16%. This decrease was due to net variances in revenue and cash expenses as discussed below.

Revenue from natural gas, natural gas liquids and crude oil sales decreased cash flow from operations by $6.0 million or 13% ($40.8 million versus $46.8 million) due mainly to the net result of lower volume sales and higher prices in natural gas, natural gas liquids and light/medium crude oil. Our introduction in Fiscal 2004 of heavy crude oil sales increased our cash flow from operations. A breakdown of the volume/price-based variances by commodity is shown in the table below.

Revenue Variances by Commodity between the Comparative Periods Presented

				Fiscal 2003 vs
	Fiscal 2004 vs Fiscal 2003			Nine-Month Fiscal Transition 2002
($000’s)	Volume-based	Price-based	Total	Volume-based	Price-based	Total
Natural gas	(362)	514	152	4,984	8,607	13,591
Natural gas liquids	(920)	607	(313)	1,332	1,302	2,634
Light/medium crude oil	(7,917)	1,567	(6,350)	6,384	116	6,500
Heavy crude oil	469	-	469	-	-	-
Total	(8,730)	2,688	(6,042)	12,700	10,025	22,725

The change in cash expenses between periods increased cash flow from operations by $2.3 million. This was the net result of certain decreases and increases. The decreases were in royalties ($3.7 million) and current income taxes ($0.6 million). The

increases were in production costs ($1.9 million), and net expenses related to net interest, and general and administrative costs ($0.1 million).

Net (loss) earnings decreased between periods by $17.3 million (a loss of $12.3 million from net earnings of $5.0 million) due to the $3.7 million decrease in cash flow from operations discussed above and a net increase of $13.6 million in non-cash expenses. Increases in non-cash expenses were to amortization and depletion expense ($12.2 million), exploration expenses ($10.3 million), and various other expenses ($0.1 million). A decrease in non-cash expenses was in future income taxes ($9.0 million).

Fiscal 2003 vs Nine-Month Fiscal Transition 2002

Cash flow from operations was $23.1 million versus $10.8 million, an increase between periods of $12.3 million or 114%. This increase was due to net variances in revenue and cash expenses as discussed below.

Revenue from natural gas, natural gas liquids and crude oil sales increased by $22.7 million ($46.8 million versus $24.1 million) due to two factors. The first factor was a difference of $12.7 million in volume sales, reflecting that the reporting periods differed in length by three months. The second factor was a $10.0 million increase due to higher weighted average prices realized in Fiscal 2003 than in Nine-Month Fiscal Transition 2002. A breakdown of the volume/price-based variances by commodity is shown in the above table.

Cash expenses decreased by $10.4 million. This was the result of increases in royalties ($7.0 million), production costs ($1.5 million), and net interest and general and administrative costs ($1.9 million).

Net earnings increased between periods by $3.0 million (to $5.0 million versus $2.0 million) due to the net result of the $12.3 million increase in cash flow from operations discussed above and an increase of $9.3 million in non-cash expenses. The increase in non-cash expenses was the net result of certain increases and decreases. The increases were in amortization and depletion expense ($5.7 million) and exploration expenses ($2.6 million). The decreases were in future income taxes and various other expenses ($1.0 million).

The cash and non-cash expense variances discussed in this section reflect mainly the differing lengths of the reporting periods to which we refer. Later in this discussion and analysis, we analyze significant increases and decreases to these expense categories as they relate to the production levels of each period.

Daily Average Production Rates and Total Production

Daily Average Production Rates by Commodity and Field, and Total Production
For the Comparative Periods Presented

					Nine- Month
					Fiscal
(Units as stated)		%		%	Transition
	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Daily average production rates
Natural gas (mcf/d)
St. Albert	7,593	(24)	9,936	(13)	11,360
Halkirk	922	(22)	1,188	(13)	1,368
Peavey/Morinville	408	(19)	504	(26)	678
Other Alberta	626	(6)	666	(13)	768
Cypress/Chowade, British Columbia	2,969	293	756	-	-
Total natural gas (mcf/d)	12,518	(4)	13,050	(8)	14,174
Total natural gas (boe/d 6:1)	2,086	(4)	2,175	(8)	2,363
Natural gas liquids (bbl/d)
St. Albert	568	(13)	656	(5)	689
Other Alberta	4	(33)	6	(33)	9
Total natural gas liquids (bbl/d)	572	(14)	662	(5)	698
Light/medium crude oil (bbl/d)
St. Albert	173	(72)	609	126	270
Other, Saskatchewan	1	-	1	-	1
Total light/medium crude oil (bbl/d)	174	(74)	610	126	271

Mantario East	61	-	-	-	-
Total heavy crude oil (bbl/d)	61	-	-	-	-
Total daily average production (boe/d)	2,893	(16)	3,447	3	3,332
Total production all products (mboe)	1,059	(16)	1,258	n/m	916

Fiscal 2004 vs Fiscal 2003
Total production of all products was 1,059 mboe versus 1,258 mboe and our total daily average production was 2,893 boe/d versus 3,447 boe/d. This represented a net decrease in average production of 554 boe/d or 16%. Of this net decrease, natural gas, natural gas liquids, and light/medium crude oil production all decreased, while heavy crude oil production increased.

The decrease in natural gas production was mainly the net result of decreases from all our Alberta properties and an increase from our British Columbia property at Cypress/Chowade. Decreases in our Alberta properties of 2,745 mcf/d (458 boe/d) were the result of naturally-declining reservoir pressures, a factor that also explains the corresponding decrease in the production of natural gas liquids. An increase in natural gas production of 2,213 mcf/d (369 boe/d) from the Cypress/Chowade field was primarily the result of the start-up of three new wells.

The decrease in daily average production of light/medium crude oil was primarily due to declining production of two St. Albert wells.

At Mantario East, we made a new-pool heavy crude oil discovery in Fiscal 2004 that added 61 boe/d to our production base.

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Total production of all products was 1,258 mboe versus 916 mboe. This would have represented an increase of 3%, had Nine-Month Fiscal Transition 2002 been annualized to 1,221 mboe.

Our total daily average production of all commodities increased by 115 boe/d or 3%, to 3,447 boe/d. Of this increase, natural gas and natural gas liquids decreased in aggregate by 224 boe/d or 7%, while crude oil increased by 339 boe/d or 125%. The aggregate decrease in natural gas and natural gas liquids was mostly the net result of a decrease due to natural declines in reservoir pressures at St. Albert and an increase due to the start-up of two new wells at Cypress/Chowade. The increase in average daily light/medium crude oil production was due to the start-up of two new wells in Fiscal 2003 and of one well in late Nine-Month Fiscal Transition 2002. All three wells were at St. Albert.

Weighted Average Commodity Prices
Our weighted average natural gas prices are a reflection of the posted New York Mercantile Exchange (NYMEX) price at the Henry Hub in Louisiana, adjusted for exchange rates, prices of competing fuels and transportation (“differentials”) back to various trading points that apply to us in Alberta and British Columbia. The natural gas price indices that affect us are the AECO-C Spot in Alberta and the B.C. Westcoast Station 2 in British Columbia.

Our weighted average light/medium crude oil prices are based on prices for West Texas Intermediate (WTI) at Cushing, Oklahoma, adjusted for differentials back to Edmonton, Alberta. The Edmonton index par price is for a 40^o to 45^ocrude having less than ½% sulphur content. The actual wellhead price for our light/medium crude varies with the quality of the oil and the cost of transportation to Edmonton.

We estimate our natural gas liquids to be 45% natural gas-based and 55% crude oil-based. Therefore, our weighted average price for liquids generally follows the above-mentioned respective indices.

Our weighted average heavy crude oil prices are based on the index, Hardisty Heavy 12^o API, for heavy crude oil in the proximity of southern Saskatchewan. Production from our new Mantario East field is, for the most part, approximately 13.4^o API.

Sproule Associates Limited, an engineering firm in Calgary, Alberta independently evaluates our reserves each year. They maintain a website showing historical and forecasted prices, which help to provide trends of the above-described indices affecting our weighted average prices. The website address is:www.sproule.com/prices/defaultprices.htm.

Management regularly employs price-trending information for its internal cash flow forecasting purposes from the websites of two firms that regularly market hydrocarbon commodities. They arewww.progas.com andwww.nexenmarketing.com.

Weighted Average Commodity Prices for the Comparative Periods Presented

					Nine- Month
					Fiscal
		%		%	Transition
(Units as stated)	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Natural gas($/mcf)	6.67	2	6.56	50	4.36
Natural gas liquids($/bbl)	30.21	9	27.68	32	20.90
Light/medium crude oil($/bbl)	50.03	7	42.98	4	41.40
Heavy crude oil($/bbl)	21.07	- -	- -	- -	- -

Fiscal 2004 vs Fiscal 2003
Our weighted average prices of natural gas, natural gas liquids and light/medium crude oil increased by 2%, 9% and 7%, respectively. As Fiscal 2004 was our first year for production of heavy crude oil, there are no weighted average price comparisons to prior periods.

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Weighted average prices realized from the sale of all our commodities increased by percentages ranging from 4% to 50%, as shown in the above table.

Hedging

We have no hedge positions. However, by varying our product sales mix of natural gas, natural gas liquids and crude oil, we manage the potential risk of single-product price volatility. Further, we vary our natural gas sales mix between AECO-spot prices and aggregator-based prices (which are, in turn, based on a blend of AECO-spot, long-term and NYMEX contracts).

Royalties, Mineral Taxes and Royalty Credits

Royalties, Mineral Taxes, Royalty Credits and Unit Total Royalties For the Comparative Periods Presented

					Nine- Month
					Fiscal
		%		%	Transition
($ 000’s unless otherwise stated)	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Crown	2,826	(40)	4,698	n/m	1,252
Freehold and overriding	5,085	(25)	6,818	n/m	3,327
Freehold mineral taxes	1,091	(19)	1,346	n/m	943
Provincial royalty credits	(399)	24	(523)	-	(178)
Total royalties⁽¹⁾	8,603	(30)	12,339	n/m	5,344
Unit total royalties per boe($)⁽¹⁾	8.12	(17)	9.81	68	5.83

⁽¹⁾Total royalties includes mineral taxes and provincial royalty credits.

Fiscal 2004 vs Fiscal 2003
Total royalties were $8.6 million versus $12.3 million. Unit total royalties expense decreased by $1.69 or 17% to $8.12 per boe. Of this decrease, 64% was mostly due to lower light/medium crude oil production that attracted heavier-than-average royalty obligations. The remainder of the decrease was due to the elimination of a gross overriding royalty charge that burdened all our production by 3%. The overriding royalty rights were acquired from the holders on July 7, 2003.

Weighted average price differentials were not a significant factor in changes to total royalty costs between the two periods.

Fiscal 2003 vsNine-Month Fiscal Transition 2002
Total royalties were $12.3 million versus $5.3 million. This would have represented an increase of 73%, had Nine-Month Fiscal Transition 2002 been annualized to $7.1 million.

Unit total royalties expense increased by a net $3.98 or 68%, to $9.81 per boe. The main factors causing increases in unit total royalties expense were higher commodity prices and heavier-than-average royalty obligations applied to two new St. Albert oil wells. The main factor causing a decrease in unit total royalties was our July 7, 2003 repurchase of three gross overriding royalty interests that previously burdened our total current and future corporate production by an aggregate of 3% (see Note 6[d] to our Financial Statements for further details).

Production Costs

Production Costs and Unit Production Costs for the Comparative Periods Presented

					Nine- Month
					Fiscal
		%		%	Transition
($ 000’s unless otherwise stated)	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Production costs	8,941	28	7,011	n/m	5,470
Unit production costs per($)	8.44	52	5.57	(7)	5.97

Fiscal 2004 vs Fiscal 2003
Total production costs were $8.9 million versus $7.0 million. Unit production costs increased by a net of $2.87 or 52%, to $8.44 per boe. Approximately half of this unit increase was due to our having proportionately greater production originating from the Cypress/Chowade fields this year, where the costs for transportation, processing, salt-water disposal and fixed costs are significantly higher than our other fields. The remainder of the increase was mainly due to additional variable costs associated with compression fees, and the continued incurrence of fixed costs versus declining production from our Alberta fields.

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Total production costs were $7.0 million versus $5.5 million. This would have represented a decrease of 4%, had Nine-Month Fiscal Transition 2002 been annualized to $7.3 million.

Unit production costs decreased by a net of $0.40 or 7%, to $5.57 per boe mainly due to the elimination of monthly processing charges for St. Albert facilities acquired at the close of Nine-Month Fiscal Transition 2002, pursuant to a sales and leaseback agreement.

Amortization and Depletion Expense (A&D)

A&D Expense and Unit A&D Expense for the Comparative Periods Presented

					Nine- Month
					Fiscal
					Transition
		%		%	2002
($ 000’s unless otherwise stated)	Fiscal 2004	Chg	Fiscal 2003	Chg
A&D before the following:	19,904	71	11,606	n/m	5,924
Impairment test adjustment	3,835	-	316	29	445
Depletion of asset retirement cost	443	347	99	57	63
Amortization of deferred items	-	-	-	-	(109)
Total A&D expense	24,182	101	12,021	n/m	6,323
Unit A&D expense per boe($)	22.83	139	9.55	38	6.90

Fiscal 2004 vs Fiscal 2003
Our total A&D expense was $24.2 million versus $12.0 million. Unit A&D expense increased by $13.28 or 139%, to $22.83 per boe. Of this increase, $3.37 per boe or 25%, was due to impairment test adjustments, of which

Cypress/Chowade accounted for 95%. The reason for the Cypress/Chowade adjustment was the downward technical revisions to our natural gas reserves caused by a combination of higher-than-expected decline rates from four producing wells, and lower reserves than expected in Fiscal 2003 from two recently-drilled development wells.

After removing the impact of the impairment test adjustments discussed above, our unit A&D expense increased by $9.91 per boe ($13.28 less $3.37 per boe). The main factors accounting for this increase were:

	•	The same reasons as discussed above at Cypress/Chowade ($8.46 per boe);
	•	Increased capital-to-reserve ratios in connection with our fields at Alexander, Morinville/Peavey, Simonette and St. Albert ($0.52 per boe);
	•	Depletion expense first-recognized in Fiscal 2004 related to our new-pool heavy crude oil discovery at Mantario East ($0.22 per boe); and
	•	Amortization of new petroleum natural gas rights ($0.65 per boe).

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Our total A&D expense was $12.0 million versus $6.3 million. This would have represented an increase of 43%, had Nine-Month Fiscal Transition 2002 been annualized to $8.4 million.

Unit A&D expense increased by a net of $2.65 or 38%, to $9.55 per boe due mainly to the following increases: $1.23 per boe due to higher capital-to-reserve ratios related to crude oil discoveries and natural gas optimizations at St. Albert in Fiscal 2003; $0.55 per boe due to significant growth in our Fiscal 2003 leasehold base; and $0.98 per boe due to additional depletion related to the July 7, 2003 repurchase of gross overriding royalty interests that previously burdened our total current and future corporate production by 3% (see Note 6[d] to our Financial Statements for further details).

Exploration Expenses
We follow the successful efforts method of accounting, whereby costs of drilling an unsuccessful well are expensed immediately if it is known the well did not result in a discovery of proved reserves. If the economic importance was not immediately known after drilling, the expensing of our drilling costs may be temporarily deferred. We expense such deferred costs after one year if near-term efforts to establish proved reserves are not foreseeable, intended, or in our control. Collectively, we report these costs as “Drilling” in the table below.

While we report our budgeted annual drilling costs, it is difficult to forecast year-over-year drilling success rates. However, three factors tend to increase or decrease our exploration expenses as they relate to drilling. They are as follows:

	•	Exploratory wells generally involve a greater degree of risk than development wells, due to the increased uncertainty in establishing proved reserves;
	•	Outpost wells generally involve more expense due to remoteness and inaccessibility to oilfield services; and
	•	Wells in which we participate at higher working interests increase costs accordingly.

The amount of our exploration expenses each year also depends upon how much seismic data we add to our library. Although seismic science does not remove all uncertainty, we incur such expenses in order to improve our knowledge base, develop new prospects and decrease the risk of drilling failures.

Exploration Expenses and Unit Exploration Expenses for the Comparative Periods Presented

					Nine- Month
					Fiscal
		%		%	Transition
($ 000’s unless otherwise stated)	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Drilling	10,167	696	1,278	n/m	325
Seismic data activity	3,669	56	2,349	n/m	934
Other	565	29	439	n/m	187
Total exploration expenses	14,401	254	4,066	n/m	1,446
Unit exploration expenses per boe($)	12.85	298	3.23	104	1.58

Fiscal 2004 vs Fiscal 2003
Total exploration expenses were $14.4 million versus $4.1 million. Unit exploration expenses increased by $9.62 or 298%, to $12.85 per boe. This unit increase is due mainly to expensing costs related to 15 unsuccessful drilling attempts, ten of which were drilled in Fiscal 2004. This compares to the expensing of one unsuccessful drilling attempt at each of Wimborne and Halkirk in Fiscal 2003. The remainder of the increase was mostly due to a proprietary, 44-square kilometer, 3D seismic program shot at Orion, compared to our share of a smaller, multi-client program shot at Wimborne in Fiscal 2003.

The following two lists show the ten wells drilled in Fiscal 2004 and the $4.5 million related to our working interest percentage share of expensed drilling costs:

	Development Wells Drilled
	•	Cypress/Chowade natural gas targets – two wells (one at 50%, one at 30%) for $1.5 million;
	•	Mantario East area heavy crude oil targets – two wells (each at 75%) for $0.4 million; and
	•	St. Albert light/medium crude oil target – one well (at 75%) for $0.2 million.

	Exploratory Wells Drilled
	•	Orion natural gas targets - two wells (one at 100%, one at 50%) for $1.6 million;
	•	Wimborne natural gas targets - two wells (each at 50%) for $0.6 million; and
	•	Flaxcombe light/medium crude oil target – one well (at 75%) for $0.2 million.

The following two lists show the five wells drilled prior to, but expensed in Fiscal 2004 for $5.7 million, representing our working interest share. Costs of $4.9 million related to the drilling of four of these five wells were deferred as capital since Fiscal 2003. The remaining costs of $0.8 million relate to a remote, outpost well that were deferred as capital since Fiscal 2001 pending Fiscal 2004 drilling results.

	Development Wells Drilled
	•	Halkirk natural gas target – one well (at 100%) for $0.5 million.

	Exploratory Wells Drilled
	•	Orion natural gas target - two wells (one at 100%, one at 50%) for $3.0 million;
	•	Cypress/Chowade natural gas target - one well (at 30%) for $1.7 million; and
	•	Wimborne natural gas target – one well (at 100%) for $0.5 million.

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Total exploration expenses were $4.1 million versus $1.4 million. This would have represented an increase of 116%, had Nine-Month Fiscal Transition 2002 been annualized to $1.9 million.

Unit exploration expenses increased by $1.65 or 104%, to $3.23 per boe. While we recognized one unsuccessful drilling attempt at each of Wimborne and Halkirk, there were none in Nine-Month Fiscal Transition 2002. Costs of seismic data also increased due to the gathering of data at Wimborne, Cypress/Chowade and Orion.

Interest Expense - Net

Net Interest Expense and Unit Net Interest Expense for the Comparative Periods Presented

					Nine- Month
					Fiscal
		%		%	Transition
($ 000’s unless otherwise stated)	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Net interest expense	576	(137)	713	n/m	453
Unit interest expense per boe($)	0.54	(5)	0.57	16	0.49

Fiscal 2004 vs Fiscal 2003
Net interest was $0.6 million versus $0.7 million. The average daily balance of our credit line operating facility decreased by $1.2 million or 8%, to $13.1 million, and the closing balance was $15.6 million.

A key factor in the decrease between periods in our operating line facility usage was a May 19, 2004 private placement financing wherein we sold 2,000,000 flow-through shares at a price of $5.60 per share and 280,000 non-flow-through shares at a price of $4.55 per share. On May 18, 2004, our facility balance was $19.3 million and on May 19, 2004, it decreased by $11.7 million to $7.6 million. This difference represented proceeds of the private placement, net of fees and expenses to date.

The effective interest rates applicable to our borrowings in Fiscal 2004 and Fiscal 2003 were 4.4% and 5.1%, respectively.

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Net interest was $0.7 million versus $0.5 million. This would have represented a minimal change, had Nine-Month Fiscal Transition 2002 been annualized to $0.7 million.

The average daily balance of our bank operating facility increased by $1.8 million or 14%, to $14.3 million, and the closing balance was $13.3 million. The effective interest rates were 5.1% in Fiscal 2003 and 5.0% in Nine-Month Fiscal Transition 2002.

General and Administrative Expenses (G&A)

G&A Expenses and Unit G&A Expenses for the Comparative Periods Presented

					Nine- Month
					Fiscal
		%		%	Transition
($ 000’s unless otherwise stated)	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Cash G&A expenses	3,317	9	3,057	n/m	1,839
Non-cash G&A (stock-based compensation)	399	11	358	- -	- -
Total G&A	3,716	9	3,415		1,839
Unit G&A expenses per boe($)	3.51	30	2.71	35	2.01

Fiscal 2004 vs Fiscal 2003
Our G&A expenses were $3.7 million versus $3.4 million. Both reporting periods contained $0.4 million in stock-based compensation expense, which is a non-cash expense. On a unit basis, our G&A costs increased by $0.80 or 30%, to $3.51 per boe. Our total G&A increased mainly due to new staff hires and certain salary increases, however, most of the increase in our unit G&A is due to decreased production being applied as the denominator.

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Our G&A expenses were $3.4 million versus $1.8 million. This would have represented an increase of 42%, had Nine-Month Fiscal Transition 2002 been annualized to $2.4 million.

Unit G&A expenses increased by a net $0.70 or 35%, to $2.71 per boe. Of this increase, 40% was due to the first-time recognition in Fiscal 2003 of stock-based compensation made available to directors and employees under our corporate stock option plan (see Note 2 to our Financial Statements for further details). Other increases were mainly attributed to: new staff hires and certain salary adjustments; computer technical and software support; gas marketing advice; and other essential professional services.

Income Tax Expense

We use the liability method of tax allocation in accounting for income taxes. Future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantially-enacted rates and laws that will be in effect when the differences are expected to reverse.

Current and Future Income Tax Expenses (Recoveries) for the Comparative Periods Presented

					Nine- Month
					Fiscal
		%		%	Transition
($000’s)	Fiscal 2004	Chg	Fiscal 2003	Chg	2002
Current income tax (recovery) expense	(52)	(108)	632	n/m	207
Future income tax (recovery) expense	(7,384)	(568)	1,579	n/m	975
Total income tax (recovery) expense	(7,436)	(436)	2,211	n/m	1,182

Fiscal 2004 vs Fiscal 2003
Total income tax recovery increased to $7.4 million from an income tax expense of $2.2 million. The recovery was consistent with our pre-tax loss and after accounting for certain reconciling items the effective rate was 37.7%, which was in line with statutory tax rates.

Fiscal 2003 vs Nine-Month Fiscal Transition 2002
Total income tax expense increased to $2.2 million from $1.2 million. This increase was consistent with our pre-tax earnings. After accounting for certain reconciling items, our effective tax rate was 30.9%, which was in line with statutory tax rates.

Income Tax Pools Available for Deduction Against Future Taxable
Income For the Comparative Periods Presented

			Nine- Month
			Fiscal	Maximum
			Transition	Annual
($000’s)	Fiscal 2004	Fiscal 2003	2002	Deduction
Canadian exploration expense⁽¹⁾	12,607	-	1,586	100%
Canadian development expense	9,276	8,893	5,246	30%
Undepreciated capital cost	14,832	10,934	10,356	20% -100%
Canadian oil and gas property expense	22,876	21,168	17,417	10%
Total income tax pools	59,591	40,995	34,605

⁽¹⁾	The Fiscal 2004 pool balance is before taking into account the renunciation of $7.5 million to flow-through shareholders of Canadian exploration expense (see Notes 6[a] and 14 to our Financial Statements for further details).

At the end of each comparative period presented above, we had total income tax pools available for deduction against future taxable income, each pool allowing maximum annual deductions ranging from 10% – 100%.

Critical Accounting Policies

Our critical accounting policies are defined as those that are important to the portrayal of our financial position and operations and require us to make judgments based on underlying estimates and assumptions about future events and their effects. Such underlying estimates and assumptions are based on historical experience and other factors that we believe to be reasonable under the circumstances. These estimates and assumptions are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as our operating environment changes. We believe the following are the most critical areas where estimates and our accounting policies can materially impact our Financial Statements. For information concerning our other significant accounting policies, see Note 2 to our Financial Statements.

Reserves Estimates

On an annual basis, we engage independent petroleum consultants to conduct evaluations of our reserves. The accuracy of reserves estimates is a matter of interpretation and judgment and is a function of the quality and quantity of available data gathered over time. For further details and a discussion of the risks involved in the reserves estimating process, see Item 3 under “Risk Factors - Estimating of Reserves and Future Net Cash Flows Risk”.

Natural Gas and Oil Interests

We follow the successful efforts method of accounting for our natural gas and oil activities, as described in Note 2 to our Financial Statements. The application of this method requires us to make significant judgments and decisions based on available geological, geophysical, engineering and economic data. The results from drilling can take considerable time to analyze. When it is determined that drilling has been unsuccessful in establishing proved reserves or where one year has elapsed since the completion of drilling and near-term efforts to establish proved reserves are not foreseeable, intended, or in our control, the costs of drilling are written off and reported as exploration expense. Drilling costs for wells that have been successful in establishing proved reserves are capitalized as natural gas and oil interests on our balance sheet.

Where we assess that the estimated undiscounted future cash flows are either partially or fully below the book value of a property as recorded in our natural gas and oil interests (“impairment test”), we either partially or fully adjust the book value downward and record a depletion expense on our income statement accordingly (“impairment test adjustment”).

Estimates of undiscounted future cash flows that we use for conducting impairment tests are subject to significant judgment decisions based on assumptions of highly uncertain future factors such as, natural gas and crude oil prices, production quantities, estimates of recoverable reserves and operating costs. Given the significant assumptions required and the strong possibility that actual future factors will differ, we consider the impairment test to be a critical accounting procedure.

During Fiscal 2004, property impairment tests resulted in an adjustment of $3.8 million to the book value of our properties at Cypress/Chowade ($3.6 million) and Peavey/Morinville ($0.2 million).

During Fiscal 2003, property impairment tests resulted in an adjustment to the book value of our Cypress/Chowade property. The total adjustment amounted to $0.3 million.

During Nine-Month Transition 2002, our property impairment tests resulted in adjustments to the book values of four properties: Alexander, Halkirk, Morinville/Peavey and Virgo. Total adjustments amounted to $0.4 million, Halkirk accounting for 74% and Alexander 21% of the total.

Accounting Policy Changes

Canadian Pronouncements
The following pronouncements have been issued by the CICA during Fiscal 2004. While we are not materially affected by these pronouncements, we will continue to assess their applicability.

Financial Instruments – Disclosure and Presentation
In January 2004, the AcSB amended CICA3860, Financial Instruments – Disclosure and Presentation, to require certain obligations that must or may be settled, at the issuer's option, by a variable number of the issuer's own equity instruments, to be presented as liabilities. These instruments were formerly presented as equity.

The AcSB concluded that when the number of an entity's own shares or other equity instruments required to settle the obligation varies with changes in their fair value, so that the total fair value of the equity instruments to be delivered is based solely or predominantly on the amount of the contractual obligation, the counterparty does not hold a residual interest in the entity until it has received the equity instruments. These instruments indicate a relationship that is more like that of a debtor–creditor relationship than an ownership one, because the amount of consideration does not vary with changes in the fair value of the issuer's own equity instruments.

Companies that have issued these types of instruments should assess the implications on debt-to-equity and other financial ratio requirements to ensure continued compliance.

These amendments harmonize the recognition of these instruments with the provisions of SFAS 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equities.

The amendments apply to fiscal years beginning on or after November 1, 2004, although earlier application is encouraged. The amendments are to be applied on a retroactive basis with restatement of prior periods. Prior period earnings will be affected since carrying costs will be presented as earnings rather than equity transactions.

Financial Instruments – Recognition and Measurement
The proposed CICA 3855 puts forward comprehensive requirements for recognition and measurement of financial instruments. An entity would recognize a financial asset or financial liability only when the entity becomes a party to the contractual provisions of the financial instrument. Financial assets and financial liabilities would, with certain exceptions, be initially measured at fair value. For financial assets and financial liabilities not classified as held for trading, the initial value recorded would include transaction costs that are directly attributable to the acquisition or issuance of the financial asset or liability.

After initial recognition, the measurement of financial assets would vary depending on the category of the asset - financial assets held for trading, held-to-maturity investments, loans and receivables, and available-for-sale financial assets.

	•	Assets classified as trading or available-for-sale would be recorded at fair value. Unrealized gains and losses on assets classified as trading would be recorded in income. Unrealized gains and losses on assets classified as available-for-sale would be recorded in comprehensive income.

	•	Held-to-maturity investments and loans and receivables would be recorded at amortized cost.

	•	Financial liabilities that are classified as held for trading would be subsequently measured at fair value.

	•	All other financial liabilities would be subsequently measured at amortized cost using the effective interest method.

A differential reporting option would be available to qualifying companies. These companies may measure financial assets classified as "available for sale" that are not designated as a hedging instrument and have no quoted market price in an active market at cost or amortized cost.

Hedges
The purpose of the proposed CICA 3865 is to set standards on when and how hedge accounting may be applied. As compared withAcG-13, Hedging Relationships, the re-exposure draft further restricts which hedging relationships qualify for hedge accounting. For example, it restricts the ability to designate a non-derivative financial instrument as the hedging instrument to hedge certain foreign currency risks.

The re-exposure draft classifies qualifying hedging relationships into three types:

	•	Fair value hedges – hedges of the exposure to changes in fair value;

	•	Cash flow hedges – hedges of the exposure to variability in cash flows; and

	•	Hedges of foreign currency exposures of net investments in self-sustaining foreign operations.

Though the accounting treatment for each type of hedging relationship is different, for perfectly effective hedges all three treatments result in the recognition of offsetting changes in earnings in the same period. For hedges that are not perfectly effective, the ineffective portion of the change in fair value of derivatives would be included in earnings in the period of the change. The accounting treatments proposed in this re-exposure draft are expected to result in changes from current practice under Canadian GAAP.

Comprehensive Income
This new section will set the standards for the reporting and display of comprehensive income. Comprehensive income is defined as the change in equity (net assets) of an enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period, except those resulting from investments by owners and distributions to owners.

A statement of comprehensive income would be included in a full set of financial statements for both interim and annual periods. The new statement would present net income and each component to be recognized in other comprehensive income. These components would include, for example, exchange gains and losses arising on translation of the financial statements of self-sustaining foreign operations, which are currently included in a separate component of shareholders' equity.

Changes in Accounting Policies and Estimates, and Errors
The AcSB has issued an Exposure Draft with a view to replacing CICA1506, Accounting Changes, with a new Section, Changes in Accounting Policies and Estimates, and Errors. The Exposure Draft proposes the following key changes:

	•	An entity would be permitted to change an accounting policy only when it is required by a primary source of GAAP, or when the change results in a reliable and more relevant presentation in the financial statements;

	•	Changes in accounting policy would be applied retroactively, unless specific transitional provisions in a primary source of GAAP permit otherwise or application to comparative information is impractical (the standard provides specific guidance as to what is considered impractical);

	•	Expanded disclosures about the effects of changes in accounting policy, estimates and errors on the financial statements; and

	•	Disclosure of new primary sources of GAAP that have been issued but have not yet come into effect and have not yet been adopted by the entity.

The proposed revised Section is expected to be harmonized with the FASB draft standard on accounting changes and error corrections, which is scheduled to be finalized by the third quarter of 2004. The expected effective date will be for fiscal years beginning on or after January 1, 2005.

Subsequent Events
This Exposure Draft proposes several significant enhancements:

	•	Extension of the period during which subsequent events are required to be considered to include events that occur between the date of the balance sheet and the date the financial statements are authorized for issue (currently, CICA3820requires consideration to the date of completion of the financial statements). "Date of authorization for issue" is defined as the date on which those charged with governance, such as the board of directors, approve the issuance of the financial statements, including the related notes.

	•	Requirement to disclose in the financial statements the date when the financial statements were authorized for issue and who gave that authorization.

	•	Requirement to update disclosures for adjusting subsequent events in light of new information received up to the date of authorization for issue of the financial statements.

The AcSB has indicated its intent to converge with IASB standards and harmonize with U.S. GAAP. The AcSB plans to issue its amendments in the fourth quarter of 2004 and expects them to be effective for fiscal periods beginning on or after January 1, 2005.

U.S. Pronouncements
The following standards issued by the FASB do not impact us at this time:

Interpretation No. 46, “Consolidation of Variable Interest Entities”, effective December 31, 2004.

FAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”, effective for financial statements issued after June 15, 2003.

FAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Post Retirements Benefits - an amendment of SFAS No. 87, 88 and 106”, effective for financial statements issued after December 15, 2003.

FAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, effective for contracts entered into or modified after June 30, 2003.

We continue to assess the applicability of these standards.

Inflation

We operate in Canada only, where inflation for our operational costs is at low levels, i.e. in the 2%-5% range.

�� Impact of Foreign Currency Fluctuations

We hold our cash reserves and receive the majority of our revenues in Canadian dollars. We incur the majority of our expenses and capital expenditures also in Canadian dollars. Therefore, an increase or decrease in the value of the Canadian dollar versus the U.S. dollar would have a minimal effect on us.

Government Policies

We are subject to regulations of the Government of Canada and the Governments of Alberta and British Columbia. Such regulations may relate directly and indirectly to our operations including production, marketing and sale of hydrocarbons, royalties, taxation, environmental matters and other factors. There is no assurance that the laws relating to our operations will not change in a manner that may materially and adversely affect us, however, there has been no material impact on us from changes to such laws in the past three fiscal periods.

Liquidity and Capital Resources

Sources and Uses of Cash

Our main business strategy is to focus on growth through full-cycle exploration and development. We supplement our main strategy with targeted acquisitions when appropriate. To carry out these capital-intensive strategies, we require cash flow from operations and an operating bank line of credit. If warranted, we would seek term debt to finance construction of long-life facilities and equity to fuel accelerated project exploration plans.

Operating activities - In any given year, our operating activities may result in cash flow timing differences where capital expenditures exceed cash flow from operations. The two key underlying drivers behind this are:

	•	Volatility in our weighted average commodity prices; and
	•	Cash flow timing differences arising from the development of longer-term projects.

Five-Year Historical Cash Flow Information

					Nine-Month
					Fiscal
					Transition
($ 000’s unless otherwise stated)	Fiscal 2004		Fiscal 2003		2002		Fiscal 2002		Fiscal 2001

Natural gas	$6.67		$6.56		$4.36		$3.81		$6.22
Light/medium crude oil	$50.03		$42.98		$41.40		$34.33		$43.60
Heavy crude oil	$21.07		-		-		-		-

Cash flow from operations;⁽¹⁾and	19,421		23,097		10,810		11,337		18,168
Capital investment program, capital
assets and other	(37,410	)	(27,102	)	(14,022	)	(26,753	)	(12,432	)
Total timing differences	(17,989	)	(4,005	)	(3,212	)	(15,416	)	5,736

Bank operating indebtedness	1,997		2,041		(2,997	)	15,593		(6,000	)
Issuance of common shares	11,789		1,511		-		455		200
Repurchases of common shares	-		-		(326	)	(290	)	(90	)
	13,786		3,552		(3,323	)	15,758		(5,890	)
Changes in non-cash working capital	(4,203	)	(453	)	(6,535	)	342		(154	)

⁽¹⁾	Included in our cash flow from operations are payments relating to the leasing of our office space (see “Contractual Obligations and Commitments” below).

Financing activities –In 1999, we established a revolving, demand bank operating loan facility with our corporate bank. On May 16, 2003, our loan was increased to $25.0 million from $21.0 million. Principal balances outstanding are charged interest at prime plus three-eighths of a percent (at December 31, 2004, the bank’s prime rate was 4.25%) and are collateralized by a general assignment of book debts and a floating charge debenture of $38.0 million covering all our assets. A standby fee of one-eighth of a percent per annum is levied on the unused portion of the facility.

The facility is subject to a semi-annual review. The next review is scheduled for April 30, 2005. This review will include assessments of our December 31, 2004 reserves and daily production estimates and a full evaluation of our financial position and operations. As at December 31, 2004, the undrawn balance of our loan facility was $9.4 million, after allowing for bank indebtedness of $8.4 million. Repayment is in full, monthly. Our loan agreement contains covenants that require prior approval of our bank (e.g. mergers, capital distributions, other pledges of security and asset disposals). At December 31, 2004, we were compliant with all covenants and we expect to remain in compliance.

The winter season is often the best time for our drilling activities, therefore, dependence on our borrowing facility may tend to be heavier at those times.

On May 19, 2004, we closed a bought-deal private placement resulting in cash proceeds, net of fees and financing costs, of approximately $11.6 million. In exchange for the cash proceeds, we issued 2,000,000 flow-through shares at $5.60 per share and 280,000 common shares (non-flow-through) at $4.55 per share (see Note 6[a] to our Financial Statements for further details). The gross proceeds of the flow-through private placement must be spent by December 31, 2005 on qualifying expenses for exploration-only activities that are specifically defined in the Income Tax Act (Canada). Net proceeds of the non-flow-through became general working capital.

At December 31, 2004, our authorized capital was 60,000,000 common shares without par value, of which 24,558,978 were issued and outstanding. Also outstanding were 1,768,300 options at prices ranging from $1.45 to $5.43 per share, each option entitling the holder to acquire one common share. The weighted average remaining contractual exercise life of these options was 3.65 years.

During Fiscal 2004, we received cash of $0.2 million from holders of stock options upon their exercise into 84,200 shares of our common stock at a weighted average exercise price of $1.99 per share.

Working capital – Changes in our working capital and net debt levels are primarily dependent upon our cash flow from operations, the size of our capital investment program, and the timing of incurred field activities.

Our sales receivables and trade payables are settled in accordance with normal industry standards while we maintain our working capital liquidity by drawing from and repaying our unutilized bank credit facility as needed.

Our year-end net debt level, comprised of working capital and the outstanding balance of our operating bank loan, reflects a debt-to-cash-flow ratio of 1.3:1 (Fiscal 2003 – 0.8:1; Nine-Month Fiscal Transition 2002 – 1.2:1 annualized; Fiscal 2002 – 1.2:1, Fiscal 2001 - nil).

Cash Requirements

Our future liquidity is dependent upon cash flows generated from our operational activities, our capital investment programs and the flexibility of capital sources. Changes in our daily average production levels and the weighted average prices we obtain for the sales of our commodities will impact our cash flow from operations and the extent to which we may draw from, or have made available to us, bank operating credit (See Item 5 Operating and Financial Review and Prospects – “Outlook for Fiscal 2005” and Item 11 Quantitative and Qualitative Disclosures About Market Risk - “Weighted Average Prices and the Effect of Adversity”).

We may seek term debt to re-finance certain assets and equity to fuel accelerated project exploration or acquisition opportunities. In the event commodities prices increase or decrease materially, we may choose to expand or contract our spending plans. Based on our production targets, our forecasts of strong commodity prices, and support from our bank loan facility that is currently established at $25.0 million, we expect to have adequate resources to meet our Fiscal 2005 cash requirements will be met.

Cash Management

As in most upstream oil and gas companies, we manage our cash throughout both positive and negative commodity price cycles. We work toward accomplishing all projects specified in our annual capital investment program budget, however, in the event our commodity prices increase or decrease materially, we may choose to expand or contract our spending plans, as warranted.

Increases or decreases in our capital spending activities may have corresponding effects on our production, net revenues, operating loan interest expense and income-related taxes, and counter-effects on our amortization and depletion expense.

Outlook for Fiscal 2005

Our primary strategy is to grow organically through the drill bit by pursuing a business model that focuses on exploration and development. At a secondary level, our strategy is to target specific acquisitions that we believe will lead to increased productivity and future prospects for exploration and development. While we believe that northeast British Columbia offers some of the best exploration opportunities in Canada for long-term sustainable growth, we intend to focus in Fiscal 2005 on a number of lower-risk projects, such as development opportunities in Saskatchewan and production enhancements in Alberta.

Our capital expenditure and exploration expense budget for Fiscal 2005 is $21.9 million. The allocation of the budget is 17% to Alberta, 31% to British Columbia, 45% to Saskatchewan and 7% to properties yet to be allocated between the three provinces. (For full details, see Item 4 Our Information – “Fiscal 2005 – Budgeted Capital Investment Program”).

Developed Properties (80% of our Fiscal 2005 Capital Investment Program Budget)
In our Fiscal 2005 Capital Investment Program budget, we have allowed for the drilling, completion and equipping of 19 development wells. Of these wells, 18 have been considered in our 2005 target production rate table shown below. The one development well that is not considered in our 2005 target production rates is at Orion. We have also allowed for other development projects that are designed to add new production and enhance existing production.

Our planned Fiscal 2005 drilling and development projects by target, project type and property, accompanied by our expected participating working interests, are as follows:

	*Development Drilling Wells Planned* Natural gas targets
	•	Halkirk – two infill Viking formation wells are planned, each at 100%
	•	Orion – one well budgeted at 100% is nearby existing production owned by a third-party in the Bluesky
		formation

	Light/medium crude oil target
	•	St. Albert – one Leduc D-3/Wabamun D-1 well at 75% is to be drilled

	Heavy crude oil targets
	•	Mantario East – fifteen in-fill, Basal Mannville wells are planned, each at 75%

	*Other Development Projects Planned* Production enhancements
	•	St. Albert – upgrades to our salt water disposal system and miscellaneous well work-overs are planned to slow the natural decline rate of natural gas, natural liquids and light/medium crude oil production and to improve operating efficiencies, at 75%
	•	Cypress/Chowade – our 30% share of the cost to add natural gas compression is budgeted
	•	Mantario East - construction of a gathering system and heavy crude oil battery is planned at 75%

	Re-completions (completions of untested zones in existing wellbores), and tie-ins of wells previously drilled
	•	Peavey/Morinville – one natural gas well is to be re-completed at 100% and one is to be tied-in at 35%

	•	Mantario East – six cased and standing heavy crude oil wells are to be equipped and tied-in at 75%
	•	Cypress/Chowade – two cased and standing natural gas wells are to be tied-in, both at 50%

Undeveloped Properties (20% of our Fiscal 2005 Capital Investment Program Budget)
In our Fiscal 2005 Capital Investment Program budget, we have allowed for the drilling, completion, equipping and tie-in of seven exploration wells. The outcome of these wells has not been considered in our 2005 target production rate table below.

Our planned Fiscal 2005 exploration projects by target and property, accompanied by our expected participating working interests are as follows:

	*Exploratory Drilling Wells Planned* Natural gas targets
	•	Cypress/Chowade – two exploratory outpost wells are budgeted, each at 30%
	•	Orion – one well is budgeted at 100%

	Natural gas, light/medium crude oil or heavy crude oil targets
	•	Unspecified Saskatchewan Properties – four wells are allowed for in the budget, each at 75%

	*Other Exploration Projects Planned* Land acquisitions and seismic data activity
	•	Cypress/Chowade – an allowance for land acquisitions and for a 15 kilometer, 2D seismic shoot is budgeted at 30%
	•	Unspecified Saskatchewan Properties – a general allowance for land acquisitions and seismic data is factored into our budget at 75%

Our Fiscal 2005 target daily average and exit production rates are 3,300 and 3,400 boe per day, respectively. Our peak production target mid-year is 3,600 boe per day. Our target production rates do not include potential increases resulting from work being conducted during the year on certain undeveloped properties. A discussion of these properties and their potential impact on 2005 production follows the table below (see Item 5 Operating and Financial Review and Prospects - “Undeveloped Properties”):

Fiscal 2005 Target Daily Averages (by Property) and Exit Production Rates

	Target Daily
(Units as stated)	Production Rates
Natural gas (mcf/d)
St. Albert	6,784
Halkirk	642
Peavey/Morinville	594
Other Alberta (three properties)	522
Cypress/Chowade, British Columbia	1,254
Total natural gas (mcf/d)	9,796
Total natural gas (boe/d 6:1)	1,633
Natural gas liquids – St. Albert (bbl/d)	481
Light/medium crude oil – St. Albert (bbl/d)	190
Heavy crude oil – Mantario East – (bbl/d)	996
Target daily average production rate (boe/d)	3,300
Target daily exit production rate (boe/d)	3,400

Sensitivity Analysis

The following table shows the effect on cash flow of certain changes in volume, price and interest rates. Numbers presented reflect the sensitivity impact on our estimated Fiscal 2005 activity.

		----------------Changes in----------------			Effect on Cash Flow
Sensitivities		Volume	Price	Rate	$(000’s)
Production – natural gas (mmcf/d)		1	-	-	2,430
	- natural gas liquids (bbl/d)	100	-	-	1,275
	- light/medium crude oil (bbl/d)	100	-	-	2,148
	- heavy crude oil (bbl/d)	100	-	-	37

Price	- natural gas ($/mcf)	-	0.50	-	1,995
	- natural gas liquids ($/bbl)	-	1.00	-	168
	- light/medium crude oil (bbl/d)	-	1.00	-	54
	- heavy crude oil ($/bbl)	-	1.00	-	311
Interest rate (%)		-	-	1	250

Contractual Obligations and Commitments

We have an operating lease in respect of our office premises, as discussed in Note 12 to our Financial Statements. Additionally, we have asset retirement obligations relating to the clean up and restoration of wellsites and associated production facilities (see Note 5 to our Financial Statements).

Contractual Obligations and Commitments

		Payments or Work Commitments Due
					By Period
		<1	1 - 3	4– 5	>5
($000’s)	Total	Year	Years	Years	Years
Operating lease obligations (office space)	696	204	492	-	-
Asset retirement obligations⁽¹⁾	4,661	129	883	277	3,372
Total	5,357	333	1,375	277	3,372

⁽¹⁾ Asset retirement obligations represent estimates of future clean-up and restoration commitments and are undiscounted.

As at December 31, 2004, we recognized $2.6 million on our balance sheet for future asset retirement obligations. We engage independent engineering consultants to assist in assessing our total future asset retirement liabilities. While we cannot predict their ultimate cost, we currently estimate the total cost to clean up all our operating facilities to be $4.7 million.

On May 19, 2004, we completed a flow-through private placement resulting in gross cash proceeds of $11.2 million. Under the private placement agreements, we are committed to spend by December 31, 2004, the $11.2 million on qualifying expenses for exploration-only activities as defined by the Income Tax Act (Canada). On February 28, 2005, we renounced the tax benefits of the exploration expenses in favour of the original flow-through shareholders. (See Note 14 to our Financial Statements for further details).

Off-Balance Sheet Arrangements

As at December 31, 2004, we had no off-balance sheet arrangements.

Item 6. Directors, Senior Management and Employees

Directors and Senior Management

The following is information regarding our Directors, Senior Management and Employees as of December 31, 2004.

Name	Position Held	Age	Residence
Directors and Executive Officers:
Wayne J. Babcock	President & CEO, Director	61	Vancouver, B.C.
Donald K. Umbach	Vice President & COO, Director	51	Vancouver, B.C.
John A. Greig	Director	63	Vancouver, B.C.
Jonathan A. Rubenstein	Director	55	Vancouver, B.C.
David J. Jennings	Director	41	Vancouver, B.C.
John Lagadin	Director	67	Calgary, Alta.
William B. Thompson	Director	60	Kelowna, B.C.
Michael A. Bardell	CFO & Corporate Secretary	58	Vancouver, B.C.
David G. Grohs	Vice President, Production	39	Vancouver, B.C.

Wayne J. Babcock
President, Chief Executive Officer, Director

Mr. Babcock, P. Geoph., holds a degree in Geophysics from the University of British Columbia and joined Amoco Canada Petroleum Company Ltd. in 1966.

Before establishing the Company in 1979, Mr. Babcock managed Amoco's geophysical exploration of Saskatchewan and Southern Alberta, Canada's western sedimentary basin.

He is a member of the Alberta Association of Professional Engineers, Geologists and Geophysicists, the Canadian Institute of Energy and is on the Board of Directors of Redcorp Ventures Ltd., a Toronto-listed mining company.

Mr. Babcock has been our President, Chief Executive Officer and a director since 1979.

Donald K. Umbach
Vice President, Chief Operating Officer, Director

Mr. Umbach holds diplomas in Business Administration & Petroleum Land Management from the Mount Royal College of Calgary, Alberta and is a member of the Canadian Association of Petroleum Landmen. He has over 30 years experience in the Canadian oil and gas industry, beginning with Hudson's Bay Oil & Gas Limited, followed by a time with a junior oil and gas company. Prior to his joining us in 1987, Mr. Umbach was principal of his own Petroleum Landman consulting firm. Mr. Umbach is a director of ours since 1990 and is Vice President and Chief Operating Officer since 1999.

John A. Greig
Director

Mr. Greig, M.Sc./P.Geol., holds a B.Sc. (honours) in Geology from McGill University in Montreal and a M.Sc. in Geology from the University of Alberta.

Mr. Greig has been a director of ours since 1990 and is presently a director of Blackstone Ventures Inc., Eurozinc Mining Corp., and Diamondex Resources Ltd.

Jonathan A. Rubenstein
Director

Between 1977 and 1994, Mr. Rubenstein was in private law practice undertaking matters in the areas of corporate commercial law, securities law, natural resource law, international law and environmental law.

Since 1994, he worked in senior positions with international mining companies based in Vancouver. Mr. Rubenstein has been a director of ours since July 1990.

Mr. Rubenstein is Vice-President and Corporate Secretary of Canico Resource Corp. and a director of Redcorp Ventures Ltd. and Cumberland Resources Ltd.

David J. Jennings
Director

Mr. Jennings is a principal of the law firm Irwin, White & Jennings in Vancouver, Canada and has been such since 1999.

Over the past decade Mr. Jennings has specialized in corporate finance and securities law with several publicly-traded companies. Mr. Jennings' practice includes initial public and additional offerings, debt offerings, venture capital financings, take-over bids and issuer bids, proxy contests, reorganizations, corporate governance matters and related transactions.

Mr. Jennings was the past Chair of the Securities Subsection of the Canadian Bar Association, British Columbia branch, and was a member of the British Columbia Securities Commission Law Advisory Committee. Mr. Jennings has written articles and lectured on the areas of corporate and securities law and venture capital financing. Mr. Jennings received his B.A. from the University of Western Ontario in 1984 and his J.D. from the University of Toronto in 1988. Mr. Jennings has been a director of ours since August, 1999.

John Lagadin
Director

Mr. Lagadin's list of achievements includes: founder of the C$5.5 billion Alliance Natural Gas Pipeline; founder and president of Direct Energy Marketing Limited, which grew to be the largest independent gas marketer in Canada; co-founder of Municipal Gas Corporation, an aggregator of residential and commercial gas customers; founder of Energy Exchange Inc., the first commodity-styled, web-based electronic exchange for the sale and purchase of natural gas; co-founder and past president of GeoScope Exploration Technologies, Inc., a company using proprietary, state-of-the-art seismic interpretation techniques to explore for oil & gas. Most recently, he founded and is Chairman and CEO of Energy Trust Marketing Ltd., a natural gas marketing company and is co-founder and Chairman of Copper Point Golf Club, a golf course located in Windermere, British Columbia that launched in 2004.

Mr. Lagadin is an independent businessman who invests in private start-up businesses and public companies with less than 10% ownership. He also manages family trust affairs.

Mr. Lagadin holds a Bachelor of Science degree in Geological Engineering from Michigan Technology University. Recently, he was awarded the Centennial Leadership Award by the Association of Professional Engineers, Geologists and Geophysicists of Alberta, in recognition of his achievements regarding Alliance Natural Gas Pipeline.

Mr. Lagadin is a former member of the Board of Directors of Alliance Natural Gas Pipeline, Cabre Exploration and Petro-Reef Resources. Mr. Lagadin has been a director of ours since August, 2000.

William B. Thompson
Director

Mr. Thompson holds a B.Sc. in physics from the University of British Columbia and is a graduate of the Stanford Executive Program. He is a member in good standing of the Professional Engineers Geologists and Geophysicists Associations of Alberta and British Columbia.

Mr. Thompson has a distinguished background in Western Canada’s oil and natural gas industry. From 1967 to 1976, Mr. Thompson worked as a district geophysicist headquartered at the Calgary and Houston offices of Amoco. During the next twenty-four years, he held numerous senior executive responsibilities for Petro-Canada of Calgary, Alberta, including the positions of vice-president Provincial and Frontier Exploration, and vice-president Business Analysis and Support Services.

In 1989, Mr. Thompson served on the Executive Committee of the Canadian Petroleum Association and for the four-year period ending 1992, he served as a director of PanArctic Oil Limited. From 1985 to 1990 he served as a director, and in 1989 he was chairman of the British Columbia Division of the Canadian Petroleum Association. Mr. Thompson has been a director of ours since December 2002.

Michael A. Bardell
Chief Financial Officer, Corporate Secretary

Mr. Bardell holds a diploma in finance and accounting and has over 35 years experience developing and directing financial, computer and money management systems. Beginning his career with Hudson's Bay Oil and Gas, he later held senior management positions in junior oil and gas companies, and in the drilling service industry.

Before joining the Company, he was controller for one of the world's largest sulphur marketing consortiums consisting of 28 major energy companies including Gulf Canada, Chevron Canada, Canadian Occidental and Union Oil.

Mr. Bardell was our controller from 1988 to 1999 and our Chief Financial Officer from 1999 to present. Mr. Bardell is a member of Financial Executives International.

David G. Grohs
Vice-President, Production

Mr. Grohs holds a Bachelor of Applied Science degree in Mechanical Engineering from the University of British Columbia and is a registered professional engineer in the provinces of British Columbia and Alberta. He has over 15 years experience in the Canadian oil and gas industry, including positions with Shell Canada Limited, Numac Energy Inc., and ENCO Gas, Ltd. Mr. Grohs has served as our Vice-President Production since March 2003 and is responsible for production operations, engineering and acquisitions.

None of our directors, officers or employees have any family relationship with one another. To the best of our knowledge, there are no arrangements or understandings with major shareholders, customers, suppliers or others, pursuant to which any person referred to above was selected as a director or member of senior management.

Compensation – Fiscal 2004

Total Compensation Paid, and Benefits Granted to Named Executive Officers and Directors

The following table sets forth all annual and long-term compensation for services in all capacities to us for Fiscal 2004 for our Chief Executive Officer and our other four most highly compensated executive officers whose

individual total compensation for Fiscal 2004 exceeded $100,000 and any individual who would have satisfied these criteria but for the fact that the individual was not serving as an officer at the end of Fiscal 2004 (collectively “the Named Executive Officers”). The information is presented in accordance with applicable Canadian and U.S. regulations regarding reporting financial information on individual persons.

Named Executive Officers

			Other Annual	Options	Exercise
Name/Position	Salary	Bonus	Compensation⁽¹⁾	Granted⁽²⁾	Price
	($)	($)	($)	(#)	($)	Expiry Date
Wayne J. Babcock
President & CEO	197,600	29,096		17,000	3.66	Sept. 20/09
Donald K. Umbach
Vice President & COO	177,840	26,186		15,600	3.66	Sept. 20/09
David G. Grohs,
Vice-President, Production	156,609	39,365		14,100	3.66	Sept. 20/09
Michael A. Bardell,
CFO & Corporate Secretary	108,472	8,700	13,500	11,100	3.66	Sept. 20/09
Jon White
Manager, Exploration	111,500	18,500		10,100	3.66	Sept. 20/09

⁽¹⁾	The Other Annual Compensation paid during reporting periods is in respect to an RRSP contribution made on behalf of the executive officer.

⁽²⁾	We have a formalized stock option plan for the discretionary granting to the Named Executive Officers of incentive stock options that are exercisable for shares of our Common Stock.

During Fiscal 2004, we paid cash compensation to our named executive officers in the aggregate sum of $887,368.

As of our most recently completed fiscal year, we had employment contracts with all of the Named Executive Officers. Each of the contracts has standard employment provisions, including salary, benefits, vacation time, non-competition and confidentiality provisions. In addition, each of the contracts requires the Named Executive Officer not to voluntarily leave his employ during actions taken by third parties to acquire control of us. If a Named Executive Officer resigns within six months of a change of control of us for the sole reason that a change of control of us has occurred, the Named Executive Officer may receive a severance package including an amount equal to 12 months salary and the economic benefit of any stock options then outstanding. If the Named Executive Officer is terminated by us without cause, such officer may receive a severance package including an amount equal to 24 months salary, the economic benefit of any stock options then outstanding, and certain health and insurance benefits for a period not to exceed 12 months.

Other than the employment contracts described above, we had, as of the end of Fiscal 2004, no compensatory plan or arrangement in respect of compensation received or that may be received by the Named Executive Officers to compensate Named Executive Officers in the event of the termination of employment (resignation, retirement, change of control) or in the event of a change in responsibilities following a change in control, where in respect of the Named Executive Officer the value of such compensation exceeds $100,000, a threshold required by Canadian securities regulations.

The following table sets forth all compensation for services in all capacities to us for Fiscal 2004 in respect of each of the non-employee directors. None of our directors have service contracts with the company relating to their serving as a director, and none of the directors will receive benefits upon termination of their position as a director. Directors who are a member of an official standing committee (i.e. audit, reserves audit, corporate governance, compensation or any other) are granted 5,000 options annually and directors who chair such committees are granted 2,500 options annually in addition to those identified above.

Compensation of Non-Employee Directors

			Other Annual	Options	Exercise
Name/Position	Salary⁽¹⁾	Bonus	Compensation	Granted (#)⁽²⁾	Price	Expiry Date
John A. Greig	Nil	Nil	Nil	17,500	$4.75	Apr 29, 2009
				15,000	$4.08	Jun 18, 2009
Jonathan A. Rubenstein	Nil	Nil	Nil	17,500	$4.75	Apr 29, 2009
				15,000	$4.08	Jun 18, 2009
David J. Jennings⁽³⁾	Nil	Nil	Nil	12,500	$4.75	Apr 29, 2009
				15,000	$4.18	Aug 21, 2009
John Lagadin	Nil	Nil	Nil	7,500	$4.75	Apr 29, 2009
				15,000	$4.18	Aug 21, 2009
William B. Thompson	Nil	Nil	Nil	10,000	$4.75	Apr 29, 2009
				15,000	$4.08	Jun 18, 2009

⁽¹⁾	During Fiscal 2004 , we did not pay any cash compensation to our directors (employee and non-employee), in their capacities as such.

⁽²⁾	We have a formalized stock option plan for the non-discretionary, automatic granting of incentive stock options to independent directors that are exercisable for shares of our Common Stock. All such grantings are allocated at the time of the director’s first election or annually based on the director’s participation as a standing committee chair or member. The options indicated above were granted pursuant to that plan.

⁽³⁾	At our Annual General Meeting held on August 25, 1999, our shareholders approved the nomination of David J. Jennings for election as director for a three-year term. He was subsequently re-appointed at the 2002 Annual General Meeting for an additional three-year term. Mr. Jennings performs legal work on our behalf as a Barrister and Solicitor with the firm of Irwin, White & Jennings (1999). Mr. Jennings’ Fiscal 2004 legal fees amounted to approximately $89,332.

Non-Cash Compensation to Directors, Officers and Employees

We have a formalized incentive stock option plan for our directors, officers and employees. The purpose of such options is to assist us in compensating, attracting, motivating and retaining those persons and to closely align the personal interests of such persons to that of our shareholders.

The following table shows the number of shares of Common Stock subject to outstanding stock options held by our directors and officers, as a group as of March 15, 2005.

Stock Options Outstanding as of March 15, 2005
(Directors/Officers, as a group)

		Number of Shares of
Expiry Date	Exercise Price	Common Stock

September 28, 2005	$2.10	250,000
April 3, 2006	$1.70	30,000
February 27, 2007	$1.75	180,000
June 18, 2008	$5.30	45,000
July 15, 2008	$4.66	110,000
August 21, 2008	$5.43	30,000
April 29, 2009	$4.75	65,000
June 18, 2009	$4.08	45,000
August 21, 2009	$4.18	30,000
September 20, 2009	$3.66	57,800
January 23, 2010	$1.45	25,000
August 16, 2010	$1.72	112,500
September 28, 2010	$2.10	18,750
April 29, 2011	$2.15	52,500
August 22, 2011	$2.10	60,000
April 29, 2012	$1.65	57,500
August 21, 2012	$1.75	60,000
December 16, 2012	$2.95	15,000
April 2, 2013	$3.91	12,500
April 29, 2013	$4.10	65,000
Total		1,321,550

The following table shows the number of shares of Common Stock subject to outstanding stock options held by employees and consultants who are neither our directors nor officers as of March 15, 2005.

Stock Options Outstanding as of March 15, 2005
(Non-Directors/Non-Officers)

		Number of Shares of
Expiry Date	Exercise Price	Common Stock
January 23, 2005⁽¹⁾	$1.45	10,000
July 30, 2005	$1.75	30,000
September 28, 2005	$2.10	48,000
February 28, 2006	$2.17	20,250
April 14, 2006	$2.25	30,800
February 27, 2007	$1.75	85,000
February 16, 2008	$3.80	30,000
July 15, 2008	$4.66	105,500
September 20, 2009	$3.66	87,200
Total		446,750

⁽¹⁾	The Company was in a trading black-out on the Expiry Date of this option. The option has been extended by a cumulative 30-trading day period which will commence once the trading blackout is lifted.

Stock Options Granted to and Exercised by Named Executive Officers

During Fiscal 2004 there were a total of 67,900 options granted to the Named Executive Officers as a group.

During Fiscal 2004, there were a total of 9,200 options exercised by named executive officers, employee directors and non-employee directors.

The following table sets forth details of the number of stock options held as of March 15, 2005 by each of the Named Executive Officers. The table also sets forth the March 15, 2005 value of unexercised in-the-money options on an aggregated basis. We have no stock appreciation rights outstanding.

Stock Options Held by Named Executive Officers

		Dollar Value of Unexercised In-the-
	Number of Unexercised Options	Money Options Held At
	Held At March 15, 2005	March 15, 2005⁽¹⁾
Name	Exercisable / Unexercisable	Exercisable / Unexercisable
Wayne J. Babcock	171,667/40,333	197,000/0
Donald K. Umbach	171,667/38,933	197,000/0
David G. Grohs	56,667/27,433	74,000/0
Michael A. Bardell	96,667/24,433	113,000/0
Jon White	55,800/20,100	58,260/0

⁽¹⁾	Value of unexercised in-the-money options calculated using the closing price of our shares of Common Stock on the Toronto Stock Exchange on March 15, 2005, less the exercise price of in-the-money stock options.

Options and Bonus Shares

During Fiscal 2004, members of the Compensation Committee recommended, and the Board of Directors approved, the granting of 87,200 options to our employees. There were no option re-pricings during Fiscal 2004. In Fiscal 2003, the Compensation Committee also affirmed a recommendation from our President and our Chief Operating Officer for the distribution of a special cash bonus over a three-year period to our Vice President, Production reflecting his exceptional performance. At the 2003 Annual General Meeting, a stock bonus plan was approved by our shareholders that provides for up to 50,000 bonus shares in the aggregate to be issued to eligible directors, officers or employees. There were no bonus shares issued in Fiscal 2004 pursuant to the 2003 Incentive Stock Bonus Plan. The Committee intends to continue a conservative approach to the issuance of these bonus shares.

The maximum number of bonus shares and options under the 2003 Incentive Stock Option Plan available to any one eligible director, officer or employee under the Bonus Plan and the 2003 Incentive Stock Option Plan is 5% of the outstanding shares of the Company.

Board Practices

Term of Office

At our annual general meeting held on August 27, 1998, our shareholders approved amending our Articles of Incorporation to provide that approximately one-third of the members of the Board of Directors be elected annually for three-year terms. At the end of Fiscal 2004, we had seven directors. The terms of all seven expire at the annual meeting of shareholders as follows:

	•	two in Fiscal 2004;
	•	two in Fiscal 2005; and
	•	three in Fiscal 2006.

Name	Term of Office Remaining	Held Office Since
Wayne J. Babcock	Three years	1980
Donald K. Umbach	Three years	1986
John A. Greig	Two years	1991
Jonathan A. Rubenstein	Two years	1991
David J. Jennings	One year	1999
John Lagadin	One year	2000
William B. Thompson	Two years	2002

Our executive officers are not appointed by the Board of Directors for any specific term but serve until they resign, their successor is duly elected and qualified, or they are removed from office or otherwise disqualified from service as one of our officers.

Committees: Audit, Audit Reserves, Compensation and Corporate Governance

The following table sets forth details relating to the composition of our Board Committees as of the end of Fiscal 2004.

List of Directors, Committees and Committee Members

		Corporate		Reserves
	Full Board	Governance	Compensation	Audit	Audit
Non-Employee Directors
John Greig	x	x	x		Chair
Jonathan Rubenstein	x	x	Chair		x
David Jennings	x	Chair	x
John Lagadin	x			Chair
Bill Thompson	x			x	x

Employee Directors
Wayne Babcock	Chair
Don Umbach	x

	*Audit Committee* - the Audit Committee is mandated to:

	•	assist the Board of Directors in fulfilling its fiduciary responsibilities relating to accounting and reporting practices and internal controls;
	•	review audited financial statements and management’s discussion and analysis of operations with the auditors;
	•	review the annual report and all interim reports with the auditors;

	•	ensure that no restrictions are placed by management on the scope of the auditor's review and examination of our accounts; and
	•	recommend to the Board of Directors the firm of auditors to be nominated by the Board of Directors for appointment by the shareholders at the annual general meeting.

Reserves Audit Committee - the Reserves Audit Committee is mandated to:

	•	assist the Board of Directors in fulfilling its oversight responsibilities with respect to our annual reserves estimates;
	•	recommend to the Board of Directors for appointment, the firm of independent qualified engineers to evaluate our annual reserves;
	•	examine the work scope, information access, resolved opinion differences and determine the independence of the independent engineering firm; and
	•	review the annual estimated reserves as prepared by the independent engineers.

Corporate Governance Committee – the Corporate Governance Committee is mandated to deal generally with corporate governance obligations and opportunities presented to us. It has prepared written mandates that define the stewardship responsibilities of the Board of Directors and its committees, implemented a risk management system, and ensured that effective communications systems are in place among the Company, its shareholders and the public. As well, the Corporate Governance Committee recommends nominees for the Board of Directors, and oversees the effective functioning of the Board of Directors and its relationship with management. In all activities the Corporate Governance Committee adheres to Canadian and U.S. statutory obligations to ensure we are in compliance with all applicable laws.

Compensation Committee - the Compensation Committee is mandated to consider and make recommendations to the Board of Directors for appropriate compensation packages for our executive officers and directors. The guiding philosophy of the Compensation Committee in determining compensation for executives has been to provide a compensation package that is flexible, entrepreneurial and geared towards attracting, retaining and motivating executive officers. The policies of the Compensation Committee encourage performance by executives to enhance our growth and profitability. Achievement of these objectives is intended to contribute to an increase in shareholder value.

Royalty Interests Acquired

We have never had a pension plan or provided compensation in the form of any plan intended to serve as incentive for long term performance greater than one financial year. However, the shareholders previously approved royalty agreements with certain officers whereby we paid annually an overriding royalty interest of 1% of our share of gross monthly production of all petroleum substances produced or deemed to be produced and marketed from or allocated to each well on all lands acquired by us since June 1, 1986 (two Named Executive Officers) and since June 1, 1987 (the third Named Executive Officer). During the year ended December 31, 2003, the Compensation Committee of the Board of Directors negotiated and reached agreements with each of Mr. Wayne J. Babcock, Mr. Donald K. Umbach and Mr. James R. Britton to repurchase the overriding royalty interests for an aggregate purchase price of $6,516,000. Under the terms of the repurchase documents, the aggregate purchase price was paid by the issuance of 1,050,666 common shares of the Company and the payment of $1,000,000 in cash. The number of common shares issued was based on a price of $5.25 per share, such price having been determined according to a daily volume-weighted average price formula applied to trading at the time of the repurchase as required by the rules of the Toronto Stock Exchange. The Compensation Committee and our independent directors determined that the purchase price was fair based upon reports by Sproule Associates Limited of Calgary, Alberta, a fairness opinion prepared by Octagon Capital Corporation of Toronto, Ontario, and input from other advisors. The repurchase transaction was completed on July 7, 2003.

Salaries and Bonuses

Since 1999 the Compensation Committee has retained the services of William M. Mercer Inc. (“Mercer”) of Calgary, Alberta to conduct thorough executive compensation reviews. As a result of the Mercer report received in 2003, the Compensation Committee found that the salary levels of our Company’s executives were “outside and below the ranges of salaries for executives in comparable positions in the peer group of oil and gas producing companies”. As a result of this, and following the closing of our acquisition of the aforementioned royalties, the Committee resolved to increase the base annual salary levels of each of the President and Chief Executive Officer, and the Vice President and Chief Operating Officer from $116,800 to $190,000 and from $116,800 to $171,000, respectively, and also to institute

discretionary bonus provisions in the employment arrangements for these officers. The distribution of such bonuses by the committee for Fiscal 2004 has not yet been considered.

After giving effect to these adjustments, the salary of each of these two executives remain below the mean of the salaries paid for the same positions by a selected peer group of companies. No subsequent increases, other than cost of living increases, have been made to the salary levels for the year ended December 31, 2004.

The Compensation Committee considers it prudent to ensure that remuneration arrangements for key executives are competitive with our peers and include an element of reward where warranted to reflect above-average performance.

The Compensation Committee further resolved that, consistent with our peer group of companies, all the above executive positions would be eligible for discretionary stock option participation.

Indebtedness and Material Interest of Committee Members

Our Board of Directors is composed of seven directors. None of the members of the Audit, Audit Reserves, Compensation and Corporate Governance Committees has any indebtedness to us nor does any have any material interest, or have any associates or affiliates that have any material interest, direct or indirect, in any actual or proposed transaction in the last fiscal year that has materially affected or would materially affect us. Additionally, no employee directors serve on any of our Board committees.

Employees

As of December 31, 2004, we employed twenty people full time in our Richmond, British Columbia office, as compared with twenty-one as of December 31, 2003. The persons employed are the President & CEO, the Vice President & COO, the CFO & Corporate Secretary, the Vice President, Production and sixteen persons occupied with technical support, company and joint venture accounting, financial reporting, office management and land administration. None of our employees are related.

In addition to the foregoing, we also receive technical services from a number of exploration, geophysical, geological, engineering, accounting and legal consultants.

Beneficial Share Ownership

The following table sets forth the Common Stock ownership of each of our directors and officers. All ownership shown is of record and reflects beneficial ownership as of March 15, 2005, and represents the number of shares of Common Stock beneficially owned, directly or indirectly, or controlled by the person listed. Unless otherwise indicated, such shares are held directly.

Beneficial Share Ownership of Directors and Officers

		Number of Shares of	Percent of
Name	Position	Common Stock⁽¹⁾	Class
Wayne J. Babcock	President & CEO, Director	1,340,303	5.4%
Donald K. Umbach	Vice President & COO, Director	734,730	3.0%
John A. Greig	Director	295,577	1.2%
Jonathan A. Rubenstein	Director	223,613	*
David J. Jennings	Director	190,000	*
John Lagadin	Director	123,600	*
William B. Thompson	Director	85,000	*
Michael A. Bardell	CFO & Corporate Secretary	330,841	1.3%
David G. Grohs	Vice President, Production	72,467	*

⁽¹⁾	Includes options exercisable within 60 days of March 15, 2005.

*	Less than 1%.

Item 7. Major Shareholders and Related Party Transactions

Major Shareholders

To the best of our knowledge, no person beneficially owns, directly or indirectly, or exercises control or direction over shares constituting more than five percent of the voting rights of our shares, other than our President and CEO, Wayne Babcock, who beneficially owns approximately 5% of our outstanding shares. Over the past three fiscal years, Mr. Babcock increased his beneficial ownership by 526,314 shares of Common Stock.

All of our outstanding shares are Common Stock without par value, each possessing equal voting rights. There is no other class of shares authorized.

Related Party Transactions

None

Interests of Experts and Counsel

None.

Item 8. Financial Information

Financial Statements and Other Financial Information

Financial statements are provided under Item 17.

There are no material legal or arbitration proceedings to which we are subject or that are anticipated or threatened.

We have never paid dividends to shareholders nor is there a policy in place to so do. All cash flow generated by us is reinvested in our operations.

Significant Changes

Item 9. The Offer and Listing

Markets and Price History of the Stock

Our shares of Common Stock are traded in Canada on the Toronto Stock Exchange (“TSX”) under the symbol “DOL” and are quoted in the United States on the National Association of Securities Dealers Automated Quotation System ("NASDAQ") SmallCap Market under the symbol “DYOLF”. Our shares of Common Stock began trading in Canada on the TSX on May 27, 1999. Prior to that date, our shares of Common Stock traded in Canada on the Vancouver Stock Exchange (“VSE”). We chose to de-list our shares of Common Stock from trading on the Vancouver Stock Exchange on August 25, 1999 in favour of our TSX listing.

As of March 15, 2005, we had 24,558,978 shares of Common Stock outstanding. At that date, we estimate 64 shareholders of record resident in Canada holding 13,720,028 shares of common stock and 735 shareholders of record

resident in the United States holding 10,833,750 shares of Common Stock. Our shares of Common Stock are issued in registered form and the number of shares of Common Stock reported to be held by record holders in Canada and the United States is taken from the records of The CIBC Mellon Trust Company, the registrar and transfer agent for our shares of Common Stock. For U.S. reporting purposes, we are a foreign private issuer.

The high and low prices for our Common Stock for the five most recent reporting periods on the VSE (up to August 24, 1999), on the TSX (starting May 27, 1999) and on The NASDAQ SmallCap Market are as follows:

	TSX (in Cdn $)		NASDAQ SmallCap (in U.S. $)
	High	Low	High	Low
Fiscal 2004	6.49	3.00	5.04	2.39
Fiscal 2003	6.49	3.10	4.97	1.99
Nine-Month Fiscal Transition 2002	4.45	1.60	3.05	1.01
Fiscal 2002	2.63	1.55	1.75	0.92
Fiscal 2001	3.00	1.55	2.06	1.00
Fiscal 2000	2.05	1.44	1.50	0.97

The high and low prices for our common stock for each quarter for the last two reporting periods on the TSX and on The NASDAQ SmallCap Market are as follows:

Prices of Common Stock	TSX (in Cdn $)		NASDAQ Small Cap (in U.S. $)
	High	Low	High	Low
Fiscal 2004
Q1 ended March 31, 2004	6.49	4.10	5.04	3.11
Q2 ended June 30, 2004	5.03	3.94	3.83	2.80
Q3 ended September 30, 2004	5.20	3.57	3.97	2.80
Q4 ended December 31, 2004	3.88	3.00	3.24	2.39
Fiscal 2003
Q1 ended March 31, 2003	4.10	3.22	3.00	1.99
Q2 ended June 30, 2003	5.75	3.91	4.25	2.33
Q3 ended September 30, 2003	5.93	4.15	4.25	2.90
Q4 ended December 31, 2003	6.49	4.61	4.97	3.50

The high and low prices for our common stock for the most recent six months on the TSX and on The NASDAQ SmallCap Market are as follows:

	TSX (in Cdn $)		NASDAQ SmallCap (in U.S. $)
Year	High	Low	High	Low

Feb/2005	3.40	2.95	2.72	2.40
Jan/2005	3.55	2.88	2.90	2.30
Dec/2004	3.49	3.00	3.00	2.39
Nov/2004	3.80	3.05	3.24	2.55
Oct/2004	3.88	3.55	3.21	2.55
Sept/2004	4.30	3.57	3.25	2.80

Item 10. Additional Information

Notice of Articles and Articles

Our objects and purposes as set forth in our Notice of Articles and Articles

Our Notice of Articles and Articles (collectively, the “Articles”) are silent as to our objects and purposes. However, under the laws of British Columbia, we have the rights of a natural person, subject to restrictions imposed by statute, and accordingly, our objects and purposes are not limited to any particular activities.

Matters relating to our Directors

Director’s power to vote on a proposal, arrangement or contract in which the director is materially interested – Section 17.4 of our Articles provides: “A director or senior officer who holds any office or possesses any property, right or interest that could result, directly or indirectly, in the creation of a duty or interest that materially conflicts with that individual’s duty or interest as a director or senior officer, must disclose the nature and extent of the conflict as required by the Business Corporations Act.” Section 17.3 of our Articles states” A director who holds a disclosable interest in a contract or transaction into which the Company has entered or proposes to enter and who is present at the meeting of directors at which the contract or transaction is considered for approval may be counted in the quorum at the meeting whether or not the director votes on any or all of the resolutions considered at the meeting.”

Director’s power, in the absence of an independent quorum, to vote compensation to themselves or any members of their body –Section 13.5 of our Articles provides: “The directors are entitled to the remuneration for acting as directors, if any, as the directors may from time to time determine or, if the directors so decide, the remuneration of the directors, if any, will be determined by the shareholders. That remuneration may be in addition to any salary or other remuneration paid to any officer or employee of the Company as such, who is also a director.” Section 13.7 of our Articles provides “If any director performs any professional or other services for the Company that in the opinion of the directors are outside the ordinary duties of a director, or if any director is otherwise specially occupied in or about the Company’s business, he or she may be paid remuneration fixed by the directors, or, at the option of that director, fixed by ordinary resolution, and such remuneration may be either in addition to, or in substitution for, any other remuneration that he or she may be entitled to receive.”

Borrowing powers exercisable by the directors and how such borrowing powers can be varied –Section 8.1 of our Articles provides: “The Company, if authorized by the directors, may: (1) borrow money in the manner and amount, on the security, from the sources and on the terms and conditions that they consider appropriate; (2) issue bonds, debentures and other debt obligations either outright or as security for any liability or obligation of the Company or any other person and at such discounts or premiums and on such other terms as they consider appropriate; (3) guarantee the repayment of money by any other person or the performance of any obligation of any other person; and (4) mortgage, charge, whether by way of specific or floating charge, grant a security interest in, or give other security on, the whole or any part of the present and future assets and undertaking of the Company.” Part 8.2 states: “Any bonds, debentures or other debt obligations of the Company may be issued with any special privileges as to redemption, surrender, drawing, allotment of or conversion into or exchange for shares or other securities, attending and voting at general meetings of the Company, appointment of directors or otherwise and may, by their terms, be assignable free from any equities between the Company and the person to whom they were issued or any subsequent holder thereof, all as the directors may determine.”

The borrowing powers of our directors may only be varied by an amendment to our Articles. A vote of at least three-quarters of our issued and outstanding shares cast at a duly called meeting is required to approve such an amendment.

Retirement or non-retirement of directors under an age limit requirement -Our Articles are silent with regard to the retirement or non-retirement of directors under an age limit requirement.

Number of shares, if any required for director’s qualification –Section 13.4 of our Articles states that “A director is not required to hold a share in the capital of the Company as qualification for his or her office but must be qualified as required by the Business Corporations Act to become, act or continue to act as a director.”

Rights, preferences and restrictions attaching to each class of shares

We have only one class of shares, our common shares.

Dividend rights, including time limit after which dividend entitlement lapses -Our shareholders have the right to receive dividends if, as and when declared by the Board of Directors. Neither the Business Corporations Act nor our Articles provides for lapses in dividend entitlement.

Voting rights -Each of our common shares entitles its holder to one vote at any annual general or other general meeting of our shareholders.

Rights to share in surplus in event of liquidation -In the event of our liquidation, dissolution or winding-up or other distribution of our assets, the holders of common shares will be entitled to receive, on a pro rata basis, all of the assets remaining after we have paid out our liabilities.

Redemption –We may purchase or otherwise acquire any of our shares at the price and upon the terms specified by resolution of our Directors and we may redeem any class of our shares in accordance with any special rights and restrictions attaching to those shares. There are no present special redemption rights or restrictions attached to our shares.

Other -Holders of common shares do not have rights to share in our profits. There are no sinking fund provisions with respect to our common shares. Common shareholders have no liability as to further capital calls by us. There are no provisions discriminating against any existing or prospective holder of our common shares as a result of such shareholder owning a substantial number of common shares. Holders of common shares do not have pre-emptive rights.

Actions necessary to change the rights of holders of our stock

In order to change the rights of all the holders of our issued and outstanding shares, a vote of at least three-quarters of all issued and outstanding shares cast at a duly called meeting is required. In order to change the rights of holders of a particular class of our stock, a vote of at least three-quarters of the issued and outstanding shares of that class cast at a duly called meeting of that class is required. If the change of rights of one class adversely affects any other class of our stock that is senior or equal to that class, then a vote of at least three-quarters of the issued and outstanding shares of the adversely affected class cast at a duly called meeting of that class is also required. We currently have only one class of shares, the common shares.

Conditions governing manner in which annual general meetings and extraordinary general meetings ofshareholders are
convoked

Annual General Meeting –Section 10.1 of our Articles states: “Unless an annual general meeting is deferred or waived in accordance with the Business Corporations Act, the Company must hold an annual general meeting at least once in each calendar year and not more than 15 months after the last annual reference date at such time and place as may be determined by the directors.”

Extraordinary General Meeting –Section 10.3 of our Articles states: “The directors may, whenever they think fit, call a meeting of shareholders. A general meeting, if requisitioned in accordance with the Business Corporations Act, shall be called by the directors or, if not called by the directors, may be called by the requisitioning shareholders as provided for under the Business Corporations Act.” Section 10.5 of our Articles provides: “The Company must send notice of the date, time and location of any meeting of shareholders, in the manner provided in these Articles, or in such other manner, if any, as may be prescribed by ordinary resolution (whether previous notice of the resolution has been given or not), to each shareholder entitled to attend the meeting, to each director and to the auditor of the Company, unless these Articles otherwise provide, at least the following number of days before the meeting: (1) if and for so long as the Company is a public company, 21 days, (2) otherwise, 10 days.”

In addition, registered holders of at least five percent of our issued and outstanding shares may request a meeting of shareholders by giving written notice of such request to us. Upon receiving proper notice, we have up to twenty-one days to respond and then up to four months to hold the requested meeting. We may choose to satisfy the request for a meeting by calling our own meeting within the four month time period.

Limitations on rights to own securities of the Company

Except as provided in theInvestment Canada Act (the "Act"), enacted on June 20, 1985, as amended, as further amended by theNorth American Free Trade Agreement (NAFTA) Implementation Act (Canada) and theWorld Trade Organization (WTO) Agreement Implementation Act, there are no limitations under the laws of Canada, the Province of British Columbia or in the charter or any other of our constituent documents on the right of non-Canadians to hold and/or vote the Common Stock.

The Act requires a non-Canadian who is a WTO investor (defined below) making a direct acquisition of control of a Canadian business with assets of $250 million or more (for 2005), to file an application for review with

Investment Canada, a federal agency created by the Act. At present we would constitute a Canadian business under the Act, although at present our asset value does not exceed the $250 million threshold. Under the Act, control of a corporation is deemed to be acquired through the acquisition of a majority of the voting shares of a corporation, and is presumed to be acquired where one-third or more, but less than a majority, of the voting shares of a corporation are acquired, unless it can be established that the Company is not controlled in fact through the ownership of voting shares.

If the non-Canadian investor is not a WTO investor, additional types of indirect acquisitions are reviewable and the financial thresholds for reviews are significantly less. As well, if a Canadian business is involved in cultural businesses, financial services, uranium or transportation services, the financial thresholds for reviews are significantly less. We are engaged in none of those businesses.

For the purposes of determining who is a “WTO investor” when an acquisition of a Canadian business occurs, the Act provides a definition that includes: an individual who is a national or a lawful permanent resident of a state that is a member of the World Trade Organization (“WTO”) (which includes the United States of America and an additional 147 member states); a government or government agency of a WTO state; an entity that is controlled by a WTO investor-controlled entity (other than a Canadian–controlled entity); and a corporation, limited partnership or trust which is not a Canadian-controlled entity of which two-thirds of its Board of Directors, general partners or trustees, as the case may be, are Canadian or WTO investors.

If a review occurs and the Minister responsible for Investment Canada is not satisfied that the investment is likely to be a net benefit to Canada, the non-Canadian shall not implement the investment or, if the investment has been implemented, shall divest himself of control of the business that is the subject of the investment.

A non-Canadian making (i) an investment to establish a new Canadian business or (ii) an investment to acquire control of a Canadian business which is not subject to review under the Act, must notify Investment Canada, before the investment is completed or within 30 days afterward, of such investment. It is intended that investments requiring only notification will proceed without government intervention unless the investment is in a specific type of business activity related to Canada's cultural heritage or national identity.

Provisions of our Notice of Articles or Articles that have the effect of delaying, deferring or preventinga change in control of us
and that would operate only with respect to a merger, acquisition, orcorporate restructuring involving us.

There are no such limitations in our Notice of Articles or Articles. However, all of our executive officers have contractual rights under employment agreements to have their stock options vest immediately and obtain 12 to 24 months severance pay in the event of a change of control of our company.

As well, under British Columbia corporate legislation, some business combinations, including a merger or reorganization or the sale, lease or other disposition of all or a substantial part of our assets, must be approved by at a special resolution of shareholders, which is set in our Articles to be at least three-quarters of the votes cast by our shareholders or, in some cases, holders of each class of shares. In some cases, a business combination must be approved by a court. Shareholders may also have a right to dissent from the transaction, in which case, we would be required to pay dissenting shareholders the fair value of their common shares provided they have followed the required procedures.

Also, see discussion of our Permitted Bid Shareholder Protection Rights Plan in “Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds – Shareholder Rights Plan.”

Provisions of our Notice of Articles or Articles governing the ownership threshold above whichmshareholder ownership must
be disclosed

There are no such provisions in our Notice of Articles or Articles.

Significant differences between law applicable to us and law of the United States with respect to thematters addressed above in
this Item 10.

Canadian securities legislation provides that a person that has direct or indirect beneficial ownership of, control or direction over, or a combination of direct or indirect beneficial ownership of, and of control or direction over, securities of the issuer carrying more than 10% of the voting rights attached to all the issuer’s outstanding voting

securities must, within 10 days of becoming an “insider”, file an insider report in the required form effective the date on which the person became an insider, disclosing any direct or indirect beneficial ownership of, or control or direction over, securities of the reporting issuer. Canadian securities legislation also provides for the filing of a report by an “insider” of a reporting issuer who acquires or transfers securities of the issuer. This insider report must be filed within 10 days after the end of the month in which the change takes place.

The U.S. rules governing the ownership threshold above which shareholder ownership must be disclosed are more stringent than those under Canadian securities legislation. Section 13 of the Exchange Act imposes reporting requirements on persons who acquire beneficial ownership (as such term is defined in the Rule 13d-3 under the Exchange Act) of more than 5% of a class of an equity security registered under Section 12 of the Exchange Act. In general, such persons must file, within 10 days after such acquisition, a report of beneficial ownership with the Securities and Exchange Commission containing the information prescribed by the regulations under Section 13 of the Exchange Act. This information is also required to be sent to the issuer of the securities and to each exchange where the securities are traded.

Material Contracts and Agreements

On May 19, 2004, we closed a bought-deal private placement with both Octagon Capital Corporation as lead underwriter and Raymond James Ltd. Pursuant to the terms of the agreement, we issued, by way of private placement, 2,000,000 flow-through common shares at $5.60 each on a firm underwriting basis. As well, at the option of the underwriters, we issued 280,000 non-flow through common shares at $4.55 each. The total gross proceeds of the offering was $12,474,000.

Exchange Controls

U.S. shareholders may experience impediments to the enforcement of civil liabilities in the United States against foreign persons such as an officer, director or expert acting on our behalf in Canada. Such difficulty arises out of the uncertainty as to whether a court in the United States would have jurisdiction over a foreign person in the United States, whether a U.S. judgment is enforceable under Canadian law and whether suits under federal securities laws could initially be brought in Canada.

There are no governmental laws, decrees, or regulations in Canada that restrict the export or import of capital or that affect the remittance of dividends, interest, or other payments to nonresident holders of the Common Stock. However, any such remittance to a non-corporate resident of the United States may be subject to a 15% withholding tax pursuant to Article XI of the reciprocal tax treaty between Canada and the United States.

Taxation

The following paragraphs set forth certain United States and Canadian federal income tax considerations in connection with the payment of dividends on and purchase or sale of our shares of Common Stock. The tax considerations are stated in general terms and are not intended to be advice to any particular shareholder. Each prospective investor is urged to consult his or her own tax advisor regarding the tax consequences of his or her purchase, ownership and disposition of shares of Common Stock.

The discussion set forth below is based upon the provisions of the Income Tax Act (Canada) (the "Tax Act"), the Internal Revenue Code of 1986, as amended (the "Code") and the Convention between Canada and the United States of America with respect to Taxes on Income and on Capital (the "Convention"), as well as United States Treasury regulations and rulings and judicial decisions. Except as otherwise specifically stated, the following discussion does not take into account or anticipate any changes to such laws, whether by legislative action or judicial decision. The discussion does not take into account the provincial tax laws of Canada or the tax laws of the various state and local jurisdictions in the United States.

Canadian Federal Income Tax Considerations

The following discussion applies only to citizens and residents of the United States and United States corporations who are not resident in Canada and will not be resident in Canada and who do not use or hold nor are deemed to use or hold such shares of Common Stock in carrying on a business in Canada.

The payment of cash dividends and stock dividends on the shares of Common Stock will generally be subject to Canadian withholding tax. The rate of the withholding tax will be 25% or such lesser amount as may be provided by treaty between Canada and the country of residence of the recipient. Under the Convention, the withholding tax generally would be reduced to 15%.

Neither Canada nor any province thereof currently imposes any estate taxes or succession duties. Provided a holder of shares of Common Stock has not, within the preceding five years, owned (either alone or together with persons with whom he or she does not deal at arm's length) 25% or more of the shares of Common Stock, the disposition (or deemed disposition arising on death) of such shares of Common Stock will not be subject to the capital gains provisions of the Tax Act.

United States Federal Income Tax Considerations

The following discussion is addressed to US holders. As used in this section, the term "US holder" means a holder that is (1) an individual citizen or resident of the United States, (2) a corporation, partnership or other entity created or organized in or under the laws of the United States or any political subdivision thereof, (3) an estate the income of which is subject to United States federal income taxation regardless of its source, or (4) a trust if a court within the United States is able to exercise primary supervision over the administration of the trust and one or more United States persons have the authority to control all substantial decisions of the trust, or a trust that has elected to be treated as a United States person. The discussion does not address all aspects of United States federal income taxation that may be relevant to US holders in light of their particular circumstances, nor does it address the United States federal income tax consequences to US holders that are subject to special rules under the Code, including, but not limited to, (i) dealers or traders in securities, (ii) financial institutions, (iii) tax-exempt organizations or qualified retirement plans, (iv) insurance companies, (v) persons holding Common Stock as a hedge or as part of a straddle, constructive sale, conversion transaction, or other risk management transaction, and (vi) holders who hold their Common Stock other than as a capital asset.

Dividends

Subject to the discussion of the "passive foreign investment company" rules below, a US holder owning shares of Common Stock must generally treat the gross amount of dividends paid by us to the extent of our current and accumulated earnings and profits without reduction for the amount of Canadian withholding tax, as dividend income for United States federal income tax purposes. To the extent that distributions exceed our current or accumulated earnings and profits, they will be treated first as a tax-free return of capital, which will reduce the holder's adjusted tax basis in his or her Common Stock (but not below zero), then as capital gain. The dividends generally will not be eligible for the "dividends received" deduction allowed to United States corporations. The amount of Canadian withholding tax on dividends may be available, subject to certain limitations, as a foreign tax credit or, alternatively, as a deduction (see discussion at "Foreign Tax Credit" below). Dividends paid by us will be treated as income from sources outside the United States, but generally will be "passive income," or in the case of certain types of taxpayers, "financial services income" for foreign tax credit purposes.

If we make a dividend distribution in Canadian dollars, the U.S. dollar value of the distribution on the date of receipt is the amount includible in income. Any subsequent gain or loss in respect of the Canadian dollars received arising from exchange rate fluctuations generally will be U.S. source ordinary income or loss.

Long-term capital gain of noncorporate taxpayers generally is eligible for preferential tax rates. Additionally, for taxable years beginning after December 31, 2002 and before January 1, 2009, subject to certain exceptions, dividends received by certain noncorporate taxpayers from “qualified foreign corporations” are taxed at the same preferential rates that apply to long-term capital gain. The maximum federal tax rate on net long-term capital gains recognized by noncorporate taxpayers currently is 15%. Provided that we are not a “passive foreign investment company,” as discussed below, we currently should meet the definition of “qualified foreign corporation.” As a consequence, dividends paid to certain noncorporate taxpayers should be taxed at the preferential rates.

Sale or Exchange of Common Stock

Subject to the discussion of the "passive foreign investment company" rules below, the sale of a share of our Common Stock generally results in the recognition of gain or loss to the US holder in an amount equal to the difference between the amount realized and the US holder's adjusted tax basis in such share. Gain or loss upon the sale of the share will be long-term or short-term capital gain or loss, depending on whether the share has been held for more than one year. The maximum federal tax rate on net long-term capital gains currently is 15% for noncorporate taxpayers and 35% for corporations. Capital gain that is not long-term capital gain is taxed at ordinary income rates. The deductibility of capital losses is subject to certain limitations.

Foreign Tax Credit

Subject to the limitations set forth in the Code, as modified by the Convention, a US holder may elect to claim a credit against his or her U.S. federal income tax liability for Canadian income tax withheld from dividends received in respect of shares of our Common Stock. Holders of our Common Stock and prospective US holders of our Common Stock should be aware that dividends we pay generally will constitute “passive income” for purposes of the foreign tax credit, which could reduce the amount of foreign tax credit available to them. The rules relating to the determination of the foreign tax credit are complex. US holders of our Common Stock and prospective US holders of our Common Stock should consult their own tax advisors to determine whether and to what extent they would be entitled to such credit. Holders who itemize deductions may instead claim a deduction for Canadian income tax withheld.

Passive Foreign Investment Company Considerations

Special rules apply to US holders that hold stock in a "passive foreign investment company" ("PFIC"). A non-U.S. corporation generally will be a PFIC for any taxable year in which either (i) 75% or more of its gross income is passive income or (ii) 50% or more of the average value of its assets consists of assets that produce, or that are held for the production of, passive income. For this purpose, passive income generally includes, among other things, interest, dividends, rents, royalties and gains from certain commodities transactions.

We believe that we should not be classified as a PFIC for the current taxable year or prior taxable years, and we do not anticipate being a PFIC with respect to future taxable years. However, there can be no assurance that we will not be considered a PFIC for any taxable year, because (1) the application of the PFIC rules to our circumstances is unclear and (2) status under the PFIC rules is based in part on factors not entirely within our control (such as market capitalization). Furthermore, there can be no assurance that the Internal Revenue Service will not challenge our determination concerning our PFIC status. Therefore, US holders and prospective US holders are urged to consult with their own tax advisors with respect to the application of the PFIC rules to them.

If, contrary to our expectations, we were to be classified as a PFIC for any taxable year, a US holder may be subject to an increased tax liability (including an interest charge) upon the receipt of certain distributions from us or upon the sale, exchange or other disposition of Common Stock, unless such US holder timely makes one of two elections. First, if, for any taxable year that we are treated as a PFIC, a US holder makes a timely election to treat us as a qualified electing fund ("QEF") with respect to such Holder's interest in Common Stock, the electing US holder would be required to include annually in gross income (1) such Holder's pro rata share of our ordinary earnings, and (2) such Holder's pro rata share of any of our net capital gain, regardless of whether such income or gain is actually distributed. In general, a US holder may make a QEF election for any taxable year at any time on or before the due date (including extensions) for filing such Holder's United States federal income tax return for such taxable year. However, Treasury regulations provide that a US holder may be entitled to make a retroactive QEF election for a taxable year after the election's due date if certain conditions are satisfied. In the event of a determination by us or the Internal Revenue Service that we are a PFIC, we intend to comply with all record-keeping, reporting and other requirements so that US holders, at their option, may maintain a QEF election with respect to us. However, if meeting those record-keeping and reporting requirements becomes onerous, we may decide, in our sole discretion, that such compliance is impractical, and will notify US holders accordingly.

As an alternative to the QEF election, US holders may elect to mark their Common Stock to its market value (a "mark-to-market election"). If a valid mark-to-market election is made, the electing US holder generally will recognize ordinary income for the taxable year an amount equal to the excess, if any, of the fair market value of their Common Stock as of the close of such taxable year over the US holder's adjusted tax basis in the Common Stock. In

addition, the US holder generally is allowed a deduction for the lesser of (1) the excess, if any, of the US holder's adjusted tax basis in the Common Stock over the fair market value of the Common Stock as of the close of the taxable year, or (2) the excess, if any of (A) the mark-to-market gains for the Common Stock included in gross income by the US holder for prior taxable years, over (B) the mark-to-market losses for Common Stock that were allowed as deductions for prior tax years.

The PFIC rules are complex. Accordingly, US holders and prospective US holders of our Common Stock are strongly urged to consult their own tax advisors concerning the impact of these rules, including the making of QEF or mark-to-market elections, on their investment or prospective investment in our Common Stock.

Financing Exploration and Development Drilling Through Canadian Income Tax Incentives

In order to encourage investment in the exploration for and development of its mineral deposits, the Canadian Income Tax Act allows Canadian taxpayers to make investments in oil and gas companies and deduct on their personal income tax return qualifying amounts spent by the oil and gas company on Canadian property. Qualifying amounts cover 100% of annual “exploration” expenses. In addition to being able to deduct their investment as an expense, the investor receives stock in the company for his or her investment. The terms of this type of investment are usually set forth in a "Flow Through Agreement" in which the company agrees not to take as an income tax deduction the amount of the proceeds expended for exploration and/or development work, but to allow the deduction to “flow through” to the investors. This flow-through type of financing is of benefit only to Canadian taxpayers.

Under the Flow-Through type of financing, the investors pay their subscription amount to us. Shares of Common Stock are issued to the investor, and we covenant to renounce to the investor, with an effective date of December 31 of a particular year, certain exploratory or specified development expenses incurred by us under a flow through share arrangement within the first 60 days of the year following that particular year.

During Fiscal 2004, we raised gross proceeds of $11.2 million through the issuance of 2,000,000 flow-through shares at a price of $5.60 per flow-through share. During Fiscal 2003 and Nine-Month Fiscal Transition 2002 we did not raise any flow-through funding.

Item 11. Quantitative and Qualitative Disclosures About Market Risk

The oil and gas industry is exposed to a variety of risks including the uncertainty of finding and recovering new economic reserves, the performance of hydrocarbon reservoirs, securing markets for production, commodity prices, interest rate fluctuations, potential damage to or malfunction of equipment and changes to income tax, royalty, environmental or other governmental regulations.

We mitigate these risks to the extent we are able by:

	•	employing highly-skilled staff and focusing them in areas where they have a strong knowledge base in order to maximize value.
	•	utilizing competent, professional consultants as support teams to company staff.
	•	performing careful and thorough geophysical, geological and engineering analyses of each prospect.
	•	using current, cost-effective and where feasible, leading-edge technology.
	•	maintaining adequate levels of property liability and business interruption insurance.
	•	focusing on a limited number of core properties.
	•	striving to be a low-cost producer to maximize Field netbacks.
	•	maintaining a balanced portfolio of sales contracts.
	•	staying informed about industry changes and trends through appropriate association memberships, publications, subscriptions and conferences.

Market risk is the possibility that a change in the prices for natural gas, natural gas liquids, condensate and oil, foreign currency exchange rates, or interest rates will cause the value of a financial instrument to decrease or become more costly to settle. Our financial instruments in Fiscal 2004 consist of accounts receivable, income taxes receivable, bank indebtedness, operating loan, accounts payable and income taxes payable.

We are exposed to commodity price risks, interest rate risks and credit risk. We have no risks associated with foreign currency exchange rates.

Commodities Price Risk

Our future financial performance remains closely linked to hydrocarbon commodity prices, which can be influenced by many factors including global and regional supply and demand, worldwide political events and weather. These factors, among others, can result in a high degree of price volatility.

Natural gas -Our natural gas portfolio is split between two primary markets, one is the Alberta Spot Market, which trades at the AECO storage hub (www.encanastorage.com/), the other is an aggregator pool called ProGas (www.progas.com).

AECO, an intra-Alberta trading hub, offers producers the opportunity to participate in natural gas transactions for terms of one day, one month, summer and winter blocks, and annually. We are currently selling our uncommitted natural gas volumes into the AECO daily spot market, however, our marketing strategy includes securing monthly and term deals, if optimal.

During Fiscal 2004, we sold 40% of our natural gas to ProGas and 60% into the AECO daily spot market. During Fiscal 2003, we sold 46% of our natural gas to ProGas and 54% into the AECO daily spot market. During Nine-Month Fiscal Transition 2002, we sold 51% to ProGas, and 49% into the AECO daily spot market.

Natural gas liquids and crude oil -We market our natural gas liquids and light/medium crude oil based on monthly prices posted by the major purchasers at Edmonton, Alberta. Our heavy crude oil is marketed based on monthly prices posted at Hardisty, Saskatchewan. The trends in these posted prices tend to correlate with the West Texas Intermediate crude oil benchmark price (one of the world’s benchmarks followed by market analysts, investors and industry), allowing for quality adjustments and location differentials.

We currently have no hedge positions, however, we manage our potential exposure to commodity price volatilities through diversification as follows:

	•	Commodity mix – our sales portfolio is comprised of natural gas, crude oil and natural gas liquids. Crude oil and natural gas liquids are sold at prices with volatilities that differ from those of natural gas; and
	•	Natural gas pricing mix – AECO pricing typically has a close correlation to NYMEX pricing, however, when the two become disconnected due to market dynamics, we are well-positioned to take advantage of premium pricing in either market area.

A financial swap is a derivative instrument whereby we and a third party agree to settle, at specified intervals, the difference between an agreed fixed commodity price, interest rate or exchange rate and floating prices or rates calculated by reference to an agreed notional volume or principal amount. We are currently not using swap contracts and have no obligation to deliver or receive quantities of natural gas, natural gas liquids or crude oil pursuant to a swap.

Weighted Average Prices and the Effect of Adversity

We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of natural gas, natural gas liquids and crude oil may have on the fair value of our gross revenues. The following table demonstrates the effects of decreases in the weight-averaged prices of our revenue-generating commodities (see also Item 5 – “Liquidity and Capital Resources - Sensitivity Analysis”).

	Weight-Averaged Prices
Fiscal 2004		Achieved	After Consideration of Adversity %
	Final	Entire
	Quarter	Period	10%	20%	30%
Natural gas ($/mcf)	6.70	6.67	6.00	5.34	4.67
Natural gas liquids ($/bbl)	33.35	30.21	27.19	24.17	21.15
Light/medium crude ($bbl)	57.14	50.03	45.03	40.02	35.02
Heavy crude oil ($/bbl)	21.07	21.07	18.97	16.86	14.75

The following table demonstrates the effects of weight-averaged pricing adversity as applied to our Fiscal 2004 gross revenues. Our cash flow from operations and earnings before taxes would experience the same effects.

Fiscal 2004	Weight-Averaged Prices
($000’s)		Achieved	After Consideration of Adversity %
	Final	Entire
Commodity Type	Quarter	Period	10%	20%	30%
Natural gas	6,882	30,802	3,080	6,160	9,240
Natural gas liquids	1,242	6,332	633	1,266	1,900
Light/Medium Crude	1,229	3,202	320	640	961
Heavy Crude oil	469	469	47	94	141

Credit Risk

In addition to market risk, our financial instruments involve, to varying degrees, risk associated with trade credit and risk associated with operatorship of joint venture properties. Substantially all of our accounts receivable result from the sale of our commoditites and from the collection of parner liabilities pursuant to joint venture agreements under which we have operatorship responsibilities. They are subject to normal industry credit risk. For example, approximately 74% of our December 31, 2004 balance of accounts receivable is due from ninecustomers, subject to normal credit risk. Further, while our largest producing properties during Fiscal 2004 were self-operated, seven out of ten active properties in which we have interests are operated by other industry companies.

We do not require collateral or other security to support financial instruments nor do we provide collateral or security to counterparties. Currently, we do not expect non-performance by any counterparty. While there can be no assurance that our no-loss record will continue, the parties who are obligated to us contractually have been consistently reliable in the past.

Interest Rate Risk

We use a revolving, floating rate credit facility, therefore, we are exposed to fluctuations in short-term interest rates. Our current borrowing rate applied to the facility is Canadian Dollar Prime plus three-eighths of a percent per annum. To minimize our exposure to rate variability, we occasionally invest a portion of our undrawn borrowing capacity in Banker’s Acceptances. We are charged a standby fee of one-eighth of a percent per annum on our undrawn borrowing capacity.

We do not engage in interest rate swaps to hedge the interest rate exposure associated with the credit agreement. If market interest rates for short-term borrowings increase by 1%, the increase in our interest expense would be immaterial (see Item 5 - “Liquidity and Capital Resources - Sensitivity Analysis”).

At December 31, 2004, we had floating debt outstanding of $15.5 million (December 31, 2003 – $13.3 million; December 31, 2002 – $11.1 million).

Item 12. Description of Securities Other than Equity Securities

Not applicable.

Part II.

Item 13. Defaults, Dividend Arrearages and Delinquencies

None

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

Shareholder Rights Plan

Our Board of Directors adopted a Permitted Bid Shareholder Protection Rights Plan (“Rights Plan”) that was ratified by the shareholders at our Annual General Meeting on July 20, 1998.

Our shareholders re-adopted the Rights Plan at our Annual General Meeting on August 23, 2001.

The Plan is designed to ensure that all of our shareholders are treated equally if a takeover bid is made for our shares of Common Stock, and that sufficient time is available for our directors and all shareholders to evaluate fully any offer and pursue alternatives to maximize shareholder value.

The Rights Plan is designed to ensure that all of our shareholders are treated equally if a takeover bid is made for our shares of Common Stock, and that sufficient time is available for our directors and all shareholders to evaluate fully any offer and pursue alternatives to maximize shareholder value. The Rights Plan provides our board of directors and shareholders with 60 days, which is longer than provided by applicable laws, to fully consider any unsolicited take-over bid without undue pressure, to allow our board of directors, if appropriate, to consider other alternatives to maximize shareholder value and to allow additional time for competing bids to emerge. If a bid is made to all shareholders, that is held open for at least 60 days and is accepted by shareholders holding more than 50% of the outstanding common shares, or is otherwise permitted by our board of directors, then the Rights Plan will not affect the rights of shareholders. Otherwise, all shareholders, except the parties making a take-over bid, will be able to acquire a number of additional common shares equal to 100% of their existing outstanding holdings at half the market price. Thus, any party making a take-over bid not permitted by the Rights Plan could suffer significant dilution. The Rights Plan is valid until the first shareholders meeting held after August 23, 2004, at which time the Rights Plan must be re-adopted by the shareholders or it will be terminated.

Item 15. Controls and Procedures

We have carried out an evaluation, under the supervision and with the participation of our management, including our Company's Chief Executive Office and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a–13e and 15d–15e under the Securities Exchange Act of 1934, as amended). Based upon that evaluation, as of December 31, 2004, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective.

There were no changes in our internal control over financial reporting during the year ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Our CEO and CFO do not expect that our disclosure controls or our internal controls will prevent all error and all fraud. Although our disclosure controls and procedures were designed to provide reasonable assurance of achieving their objective, a control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based partly on certain

assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

Item 16(A). Audit Committee Financial Expert

The Board of Directors has determined that Mr. William Thompson possesses the necessary attributes for designation as the Company's audit committee financial expert and the Board has designated him as its audit committee financial expert.

Item 16(B). Code of Ethics

Our website at http://www.dynamicoil.com/corporate/conductethics.htm contains our combined Code of Conduct and Ethics, which applies to all of our directors, officers and employees. Any amendment to the Code of Conduct and Ethics that applies to our directors or executive officers will be disclosed on our website, and any waiver of the Code of Conduct and Ethics for directors or executive officers may be made only by our Board of Directors or our Audit Committee and will be disclosed on our website.

Item 16(C). Principal Accountant Fees and Services

The following table shows the fees billed for the audit and other services provided by Ernst & Young LLP for Fiscals 2004 and 2003.

Independent Registered Public Accounting Firm Fees

(000’s)	Fiscal 2004	Fiscal 2003
Audit-related fees⁽¹⁾	132,427	126,590
Tax fees⁽²⁾	18,336	45,496
All other fees⁽³⁾	14,268	16,176
Total	165,031	188,262

⁽¹⁾	Audit related fees are fees for professional services provided in connection with the audit of the annual, and quarterly assistance with, our financial statements, and services provided in connection with other statutory and/or regulatory filings.

⁽²⁾	Tax related fees consisted of fees for services regarding federal and provincial tax compliance, filing and reporting.

⁽³⁾	All other fees in Fiscal 2004 were primarily for the assistance with Sarbanes Oxley Section 404 compliance. In Fiscal 2003, the fees were for tax advice related to a gross overriding royalty repurchase transaction that closed on July 7, 2003.

The Audit Committee pre-approves all audit services to be performed by Ernst &Young, LLP.

Item 16(D). Exemption from the Listing Standards for Audit Committees

Not Applicable

Item 16(E). Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Not Applicable

Part III.

Item 17. Financial Statements

Report of Independent Registered Public Accounting Firm	F-1

Balance Sheets as of December 31, 2004 and December 31, 2003	F-2

Statements of Operations and (Deficit) Retained Earnings for the years ended December 31, 2004, December 31, 2003 and the Nine-Months Ended December 31, 2002	F-3

Statements of Cash Flows for the years ended December 31, 2004, December 31, 2003 and the Nine-Months Ended December 31, 2002	F-4

Notes to Financial Statements	F-5

Item 18. Financial Statements

(a)See Item 17.

(b)n/a

Item 19. Exhibits

(a) Financial Statements:See Contents of our Financial Statements.
(b) Exhibits:See Index to Exhibits.

Signatures

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

Date: March 29, 2005

Dynamic Oil & Gas, Inc.

By /s/ Michael A. Bardell

Michael A. Bardell
Chief Financial Officer & Corporate Secretary

Financial Statements

Dynamic Oil & Gas, Inc.
December 31, 2004 and 2003

REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM

To the Shareholders of
Dynamic Oil & Gas, Inc.

We have audited the balance sheets ofDynamic Oil & Gas, Inc.as at December 31, 2004 and 2003 and the statements of operations and (deficit) retained earnings and cash flows for the years ended December 31, 2004 and December 31, 2003 and the nine months ended December 31, 2002. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2004 and December 31, 2003 and the results of its operations and its cash flows for the years ended December 31, 2004 and December 31, 2003 and the nine months ended December 31, 2002 in accordance with Canadian generally accepted accounting principles.


Vancouver, Canada, March 7, 2005.	Chartered Accountants

F-1

Dynamic Oil & Gas, Inc.
Incorporated under the laws of British Columbia

BALANCE SHEETS
(in Canadian dollars)

As at December 31

	2004		2003
	$		$

ASSETS[note 4]
Current
Accounts receivable[note 10]	7,565,975		6,962,387
Prepaid expenses	361,277		356,449
Income taxes receivable	541,487		—
Total current assets	8,468,739		7,318,836
Natural gas and oil interests[note 3]	56,726,494		57,083,789
Capital assets[note 3]	414,913		365,561
Future income tax asset[note 7]	2,082,092		—
	67,692,238		64,768,186

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current
Bank indebtedness	1,083,000		1,386,238
Operating loan[note 4]	15,550,000		13,250,000
Accounts payable and accrued liabilities	17,348,723		11,335,946
Income taxes payable	—		659,519
Total current liabilities	33,981,723		26,631,703
Asset retirement obligations[note 5]	2,555,756		1,587,733
Future income tax liability[note 7]	—		5,617,723
Total liabilities	36,537,479		33,837,159
Commitments[note 12]

Shareholders’ equity
Share capital[note 6]	39,852,368		27,747,487
Contributed surplus[note 6[c]]	757,689		358,229
(Deficit) retained earnings	(9,455,298	)	2,825,311
Total shareholders’ equity	31,154,759		30,931,027
	67,692,238		64,768,186

See accompanying notes

On behalf of the Board:

	/s/ Wayne Babcock	/s/ Donald Umbach
	Director	Director

F-2

Dynamic Oil & Gas, Inc.

STATEMENTS OF OPERATIONS AND
(DEFICIT) RETAINED EARNINGS
(in Canadian dollars)

					Nine Months
	Year Ended		Year Ended		Ended
	December 31,		December 31,		December 31,
	2004		2003		2002
	$		$		$

REVENUE
Natural gas, liquids and oil sales	40,805,507		46,847,927		24,122,754
Royalties	(9,002,506	)	(12,861,990	)	(5,521,583	)
Production costs	(8,940,597	)	(7,010,610	)	(5,470,467	)
	22,862,404		26,975,327		13,130,704
Provincial royalty credits	399,223		523,278		178,098
	23,261,627		27,498,605		13,308,802

EXPENSES
General and administrative	3,715,663		3,414,751		1,839,496
Interest expense	578,112		724,897		454,251
Interest income	(1,836	)	(11,675	)	(1,732	)
Accretion of asset retirement obligation[note 5]	102,836		93,843		63,876
	4,394,775		4,221,816		2,355,891

Earnings from operations before the following:	18,866,852		23,276,789		10,952,911
Amortization and depletion[note 3]	24,182,205		12,021,474		6,322,863
Exploration expenses	14,401,131		4,065,885		1,446,178
Gain on sale of natural gas and oil interests	—		—		(2,139	)
(Loss) earnings before taxes	(19,716,484	)	7,189,430		3,186,009
Income tax expense (recovery)[note 7]
- Current	(51,730	)	632,294		207,000
- Future	(7,384,145	)	1,578,834		974,703
Net (loss) earnings	(12,280,609	)	4,978,302		2,004,306

Earnings (deficit), beginning of period	2,825,311		(2,152,991	)	(4,025,241	)
Premium on purchase and cancellation of
common shares	—		—		(132,056	)
(Deficit) retained earnings, end of period	(9,455,298	)	2,825,311		(2,152,991	)

Net (loss) earnings per share[note 8]
basic	(0.52	)	0.23		0.10
diluted	(0.52	)	0.23		0.10

See accompanying notes

F-3

Dynamic Oil & Gas, Inc.

STATEMENTS OF CASH FLOWS
(in Canadian dollars)

					Nine Months
	Year Ended		Year Ended		Ended
	December 31,		December 31,		December 31,
	2004		2003		2002
	$		$		$

OPERATING ACTIVITIES
Net (loss) earnings	(12,280,609	)	4,978,302		2,004,306
Add (deduct) items not involving cash:
Accretion of asset retirement obligation	102,836		93,843		63,876
Amortization and depletion	24,182,205		12,021,474		6,322,863
Stock based compensation	399,460		358,229		—
Future income tax (recovery) expense	(7,384,145	)	1,578,834		974,703
Exploration expenses	14,401,131		4,065,885		1,446,178
Gain on sale of natural gas and oil interests	—		—		(2,139	)
	19,420,878		23,096,567		10,809,787
Changes in non-cash working capital affecting
operating activities[note 9[a]]	(4,309,893	)	5,197,611		646,829
Cash provided by operating activities	15,110,985		28,294,178		11,456,616

FINANCING ACTIVITIES
Bank indebtedness	(303,238	)	(133,685	)	677,111
Operating loan	2,300,000		2,175,000		(3,675,000	)
Shares issued for cash	11,789,211		1,510,858		—
Share repurchases	—		—		(325,948	)
Cash provided by (used in) financing activities	13,785,973		3,552,173		(3,323,837	)

INVESTING ACTIVITIES
Purchase of capital assets	(225,087	)	(308,387	)	(84,420	)
Natural gas and oil interests	(22,774,931	)	(22,727,557	)	(12,493,116	)
Exploration expenses	(14,401,131	)	(4,065,885	)	(1,446,178	)
Settlement of asset retirement obligations	(9,057	)	—		—
Proceeds on sale of natural gas and oil interests	—		—		2,139
Changes in non-cash working capital affecting
investing activities[note 9[b]]	8,513,248		(4,744,522	)	5,888,796
Cash used in investing activities	(28,896,958	)	(31,846,351	)	(8,132,779	)

Decrease in cash and cash equivalents	—		—		—
Cash and cash equivalents, beginning of period	—		—		—
Cash and cash equivalents, end of period	—		—		—

Supplemental disclosures of cash flow information
Cash paid (received) during the year for:
Interest	595,903		555,536		459,237
Income taxes	1,148,276		(150,408	)	760,132

See accompanying notes

F-4

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

1. DESCRIPTION OF BUSINESS

Dynamic Oil & Gas, Inc. (the “Company”) was incorporated under the laws of the Province of British Columbia on March 27, 1979. The Company’s principle business is the acquisition, exploration, development and production of natural gas and oil interests in Western Canada.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting principles

The Company prepares its accounts in accordance with Canadian generally accepted accounting principles which, as applied in these financial statements, conform in all material respects with the accounting principles generally accepted in the United States, except as explained in note 11.

Change in fiscal year end

Effective December 31, 2002, the Company changed its fiscal year end from March 31 to December 31. The following is a summary of selected financial information for the comparative twelve month periods ended December 31, 2004, 2003 and 2002. The selected financial information for the twelve months ended December 31, 2002 is unaudited.

Results of operations and cash flows

	December 31,		December 31,		December 31,
	2004		2003		2002
Twelve months ended	$		$		$

Natural gas, liquids and oil sales	40,805,507		46,847,927		30,730,477
Net (loss) earnings	(12,280,609	)	4,978,302		2,004,306
Net (loss) earnings per share
basic	(0.52	)	0.23		0.02
diluted	(0.52	)	0.23		0.02
Cash flows
provided by operating activities	15,110,985		28,294,178		15,215,456
provided by (used in) financing activities	13,785,973		3,552,173		(4,331,528	)
used in investing activities	(28,896,958	)	(31,846,351	)	(10,900,821	)

F-5

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)

Use of estimates

The preparation of financial statements in conformity with Canadian generally accepted accounting principles requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.

Natural gas and oil interests

The Company uses the successful efforts method to account for its natural gas and oil interests. Lease acquisition costs are amortized over their holding period prior to the discovery of proved producing reserves. Geological and geophysical costs are expensed in the period in which they are incurred and costs of drilling an unsuccessful well are expensed when it becomes known the well did not result in a discovery of proved reserves or where one year has elapsed since the completion of drilling and near-term efforts to establish proved reserves are not foreseeable, intended, or in the Company’s control. All other costs of exploring and developing for proved reserves become capitalized natural gas and oil interests.

The costs of proved producing interests including related plant and equipment are depleted on a unit-of-production basis, based on the Company’s working interest share of proved producing natural gas and oil reserves, before royalties.

Natural gas and oil interests are recorded at cost less accumulated amortization and depletion. Natural gas and oil interests are assessed periodically for potential impairment to ensure that the carrying value of properties on the balance sheet is recoverable. If a property's carrying value exceeds the sum of undiscounted future cash flows, its value is impaired. The property is then assigned a fair value equal to its estimated discounted future cash flows and the excess carrying value is charged to amortization and depletion expense.

Joint interests

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

F-6

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)

Capital assets

Capital assets are recorded at cost, less accumulated amortization. Amortization is provided on a straight-line basis at the following rates:

Furniture and fixtures	- 10.0% per annum
Computer equipment	- 33.3% per annum

Income taxes

The liability method is used in accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse.

Asset retirement obligations

The Company’s asset retirement obligations relate primarily to retirement obligations associated with tangible assets, such as wellsites and associated facilities. The fair value of an asset retirement obligation (“ARO”) is recognized in the period in which it is incurred when a reasonable estimate of the fair value can be made. The fair value of the estimated ARO is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on a unit-of-production basis over the life of associated proved producing reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted costs also result in an increase or decrease to the ARO. Actual costs incurred upon settlement of the ARO are charged against the ARO to the extent of the accreted liability recorded. Any difference between the actual costs incurred upon settlement of the ARO and the recorded liability is recognized as a gain or loss in the Company’s earnings at that time.

Revenue recognition

Revenues from crude oil, natural gas and natural gas liquids are recorded when delivered and title passes to customers.

F-7

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)

Stock-based compensation

The Company grants stock options to employees, directors and consultants pursuant to a stock option plan described in note 6[b]. The Company uses the fair value method of accounting for all stock-based awards granted, modified or settled since January 1, 2003. For awards granted, modified or settled prior to January 1, 2003, the Company discloses the pro forma effects to the net (loss) earnings and (loss) earnings per share for the period as if the fair market value had been used at the date of grant. The pro forma information is presented in note 6[c].

Foreign currency translation

All monetary assets and liabilities expressed in foreign currencies are translated at rates of exchange in effect at the end of the year. All other assets and liabilities are translated at the rates prevailing at the dates the assets were acquired or liabilities incurred. The resulting foreign currency translation gains and losses are included in the determination of net earnings. Revenues and expenses are translated at the average exchange rate for the period.

Measurement uncertainty

The amounts recorded for depletion and amortization of natural gas and oil interests and asset retirement obligations are based on estimates. Assessments for impairments in asset carrying costs are based on independent estimates of the future cash flows from the Company’s proved producing reserves. Such estimates result mainly from studies that combine well-by-well recovery factors, future commodity prices and field operating costs. By their nature these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be significant.

Earnings per share

The Company utilizes the treasury stock method in the determination of diluted per share amounts. Under this method, the diluted weighted average number of shares is calculated assuming that the proceeds arising from the exercise of outstanding, in-the-money options, are used to purchase common shares of the Company at their average market price for the period.

F-8

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

3. NATURAL GAS AND OIL INTERESTS, AND CAPITAL ASSETS

		Accumulated
		Amortization and	Net Book
	Cost	Depletion	Value
	$	$	$

December 31, 2004
Natural gas and oil interests	116,246,542	59,520,048	56,726,494
Furniture, fixtures and computer equipment	709,089	294,176	414,913

December 31, 2003
Natural gas and oil interests	94,425,822	37,342,033	57,083,789
Furniture, fixtures and computer equipment	770,910	405,349	365,561

At December 31, 2004, costs of $14,580,869 [2003 - $16,238,852] related to non-producing assets have been excluded from the calculation of amortization and depletion.

In the year ended December 31, 2004, the Company recorded asset write-downs due to impairment tests of $3,835,468 [year ended December 31, 2003 - $316,213] to reflect the excess of the net book value of the Company’s natural gas and oil interests over its estimated recoverable amounts. The write-downs were included in amortization and depletion expense.

4. OPERATING LOAN

During 2004, the Company’s bank, the National Bank of Canada, made available the amount of $25,000,000 [2003 - $25,000,000] to the Company under a revolving, demand credit facility. Principal balances outstanding bear interest at prime plus 3/8% [bank prime rate at December 31, 2004 - 4.25%; December 31, 2003 - 4.5%; December 31, 2002 - 4.5%] . They are collateralized by a general assignment of book debts and a floating charge debenture of $38,000,000 covering all the assets of the Company. The effective average interest paid during the year ended December 31, 2004 was 4.4% [during the year ended December 31, 2003 - 5.1%; during the nine-month period ended December 31, 2002 - 5.0%] . A standby fee of 0.125% per annum is levied on the unused portion of the facility and is included in interest expense.

F-9

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

5. ASSET RETIREMENT OBLIGATION

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligation associated with the retirement of oil and gas properties:

	December 31,	December 31,	December 31,
	2004	2003	2002
	$	$	$

Asset retirement obligation, beginning of period	1,587,733	1,087,223	956,559
Liabilities incurred	865,187	406,667	66,788
Accretion expense	102,836	93,843	63,876
Asset retirement obligation, end of period	2,555,756	1,587,733	1,087,223

The total undiscounted amount of estimated cash flows required to settle the obligation at December 31, 2004 is $4,661,369 [at December 31, 2003 - $3,308,669; at December 31, 2002 - $2,109,750], which has been discounted using an average credit-adjusted risk free rate of 5.5% . These payments are expected to be made over the next 50 years with 27% of the costs incurred within the next 5 years.

F-10

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL

The Company is authorized to issue 60,000,000 common shares without par value.

[a] Issued and outstanding

The following table sets forth the issued and outstanding common shares:

	December 31,		December 31,		December 31,
	2004		2003		2002
	Number		Number		Number
	of		of		of
	shares		shares		shares
	#	$	#	$	#		$

Balance at beginning
of period	22,194,778	27,747,487	20,272,530	20,720,629	20,462,230		20,914,522
Stock options exercised	84,200	167,450	871,582	1,510,858	—		—
Shares issued on flow-through
private placement	2,000,000	10,752,216	—	—	—		—
Shares issued on private
placements	280,000	1,185,215	—	—	—		—
Shares issued to repurchase gross
overriding royalty interests
[note 6[d]]	—	—	1,050,666	5,516,000	—		—
Share repurchases and
cancellations	—	—	—	—	(189,700	)	(193,893	)
Balance at period end	24,558,978	39,852,368	22,194,778	27,747,487	20,272,530		20,720,629

On April 30, 2004 the Company issued 2,000,000 flow-through shares at $5.60 per share through private placement for total proceeds of $11,200,000 less a net reduction of $447,784 for fees and expenses of $763,454 and related future income tax asset of $315,670. The Company also issued 280,000 common shares at $4.55 per share for total proceeds of $1,274,000 net of issue costs of $88,785.

Gross proceeds from the flow-through shares will be used to incur qualifying Canadian Exploration Expense (“CEE”) as defined in the Income Tax Act (Canada), and the Company expects to renounce in 2005 such CEE in favour of the original holders of the flow-through shares in an amount equal to the issue price for each flow-through share. At that time a future income tax liability of approximately $3,949,000 will be recognized and share capital reduced by a like amount [see note 14].

F-11

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

[b] Stock option plan and options outstanding

Under the Company’s stock option plan, the Company has the ability to grant options to directors, officers, employees and non-employees with a maximum term of five years. Those granted prior to February 28, 2001 vest upon date of grant; those granted on February 28, 2001 and thereafter, vest in equal amounts over three years from the date of grant.

In addition, options granted to the Company’s outside directors prior to June 19, 2003 had a maximum term of ten years and those granted on June 19, 2003 and thereafter, have a maximum term of five years. All options to outside directors are automatically granted pursuant to the Company's stock option plan and are allocated at the time of the director's first election or annually based on the director's participation as a standing committee chair or member. All such options granted vest upon date of grant.

During the year ended December 31, 2004, options issued totaled 285,000 [145,000 to either inside directors, officers, employees or non-employees; 140,000 to outside directors]. The exercise price of each option granted under the plan equals the amount designated in the individual agreement, which is based on the fair value of the stock at the date of grant.

A summary of the status of the Company’s stock option plan as of December 31, 2004 is presented below:

	December 31, 2004			December 31, 2003			December 31, 2002
	Number of		Weighted	Number of		Weighted	Number of	Weighted
	Shares		Average	Shares		Average	Shares	Average
	Under Option		Exercise Price	Under Option		Exercise Price	Under Option	Exercise Price
	#		$	#		$	#	$

Outstanding at beginning
of period	1,615,834		2.61	2,077,750		1.83	1,930,250	1.83
Granted	285,000		4.03	421,000		4.61	147,500	1.88
Exercised	(84,200	)	1.99	(871,582	)	1.73	—	—
Forfeited	(48,334	)	3.00	(11,334	)	2.83	—	—
Outstanding at period end	1,768,300		2.86	1,615,834		2.61	2,077,750	1.83
Options exercisable at
period end	1,371,300		2.64	1,081,667		2.33	1,641,250	1.84

Exercise prices for the options outstanding as of December 31, 2004 ranged from $1.45 to $5.43 per share. These options have a weighted average remaining contractual life of 3.65 years.

F-12

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

At December 31, 2004 the following stock options were outstanding and exercisable:

	Options Outstanding			Options Exercisable
		Weighted Average		Number of	Weighted
	Number of	Weighted	Remaining	Options	Average
Exercise	Shares Under	Average	Contractual	Currently	Exercise
Price	Option	Exercise Price	Life	Exercisable	Price
$	#	$	(Years)	#	$

1.00 - 1.49	35,000	1.45	0.06	35,000	1.45
1.50 - 1.99	555,000	1.73	3.86	466,667	1.73
2.00 - 2.49	480,300	2.12	2.34	480,300	2.12
2.50 - 2.99	15,000	2.95	7.96	15,000	2.95
3.50 - 3.99	187,500	3.70	4.70	22,500	3.86
4.00 - 4.49	140,000	4.11	6.30	140,000	4.11
4.50 - 4.99	280,500	4.68	3.72	136,833	4.71
5.00 - 5.49	75,000	5.35	3.54	75,000	5.35
	1,768,300	2.86	3.65	1,371,300	2.64

[c] Accounting for stock options

During the years ended December 31, 2004 and 2003, the Company used the fair value based method to account for stock options granted to directors, employees and non-employees, resulting in a decrease to earnings and a corresponding increase to contributed surplus of $399,460 [year ended December 31, 2003 - $358,229]. During the nine-month period ended December 31, 2002, the Company used the same method to expense only those stock options granted to non-employees.

F-13

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

The following table shows pro forma net (loss) earnings and net (loss) earnings per common share had the Company applied the fair-value based method of accounting for all stock options outstanding:

				Nine Months
	Year Ended		Year Ended	Ended
	December 31,		December 31	December 31,
	2004		2003	2002
	$		$	$

Net (loss) earnings:
as reported	(12,280,609	)	4,978,302	2,004,306
pro forma	(12,381,302	)	4,856,567	1,798,630
Basic net (loss) earnings per common share:
as reported	(0.52	)	0.23	0.10
pro forma	(0.52	)	0.23	0.09
Diluted net (loss) earnings per common share:
as reported	(0.52	)	0.23	0.10
pro forma	(0.52	)	0.22	0.09

The Black-Scholes options valuation model was used to estimate the fair value of stock options. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. As changes in the subjective input assumptions can materially affect the fair value estimate, the existing models do not necessarily provide a reliable single measure of the fair value of the Company’s stock options. The fair value of option grants using the Black-Scholes model is estimated on the date of grant using the following weighted-average assumptions:

			Nine Months
	Year Ended	Year Ended	Ended
	December 31,	December 31	December 31,
	2004	2003	2002
	$	$	$

Dividend yield	0%	0%	0%
Expected volatility	47%	51%	57%
Risk-free interest rate	4.25%	4.00%	5.00%
Expected lives	3 years	3 years	3 years

The weighted average fair value per share of stock options granted during the year ended December 31, 2004 was $1.44 [year ended December 31, 2003 - $1.78] .

F-14

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

[d] Repurchase of gross overriding royalty interests

Three of the Company’s officers were entitled to receive compensation pursuant to royalty agreements that had previously been approved by shareholders. The royalty agreements provided for payment of an overriding interest of 1% of the Company’s share of gross production of all petroleum substances on lands acquired by the Company since June 1, 1986 for two of the three officers and June 1, 1987 for the third officer.

On July 7, 2003, the Company repurchased from the three Company officers their gross overriding royalty interests for $6,516,000. The aggregate purchase price was paid by the issuance of 1,050,666 common shares of the Company and the payment of $1,000,000 in cash. The number of common shares was based on a price of $5.25 per share, such price being the daily volume-weighted average price for July 7, 2003. The transaction was recorded at the exchange amount determined by an independent valuation.

The gross overriding royalty expense pursuant to the agreements, was $752,362 during the period January 1 to July 7, 2003 [nine-month period ended December 31, 2002 - $681,493].

At the time of initial recognition, proved producing assets in natural gas and oil interests on the Company’s balance sheet included $9,711,308 for the repurchase of overriding royalty interest. This amount was comprised of the aggregate repurchase price of $6,516,000 paid to the vendors, plus the related future income taxes of $3,195,308 which requires recognition in accordance with accounting rules under CICA Handbook Section 3465. The carrying value of the repurchase is subject to depletion and periodic impairment assessments.

F-15

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

7. INCOME TAXES

Future income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s future tax assets and liabilities are as follows:

	December 31,	December 31,
	2004	2003
	$	$

Long term future tax assets (liabilities):
Tax basis of oil and gas interests
and fixed assets greater than book basis	1,397,107	(5,843,546	)
Finance charges	247,126	100
Asset retirement obligation	437,359	225,723
Net future tax assets (liabilities)	2,082,092	(5,617,723	)

During the year, deductions taken from the Company's available tax pools were exceeded by add-backs in amortization and depletion expense, and exploration expense, thereby creating a significant change in the temporary difference from the previous year.

The reconciliation of income tax attributable to operations computed at the statutory tax rates to income tax (recovery) expense is:

							Nine Months
	Year Ended			Year Ended			Ended
	December 31, 2004			December 31, 2003			December 31, 2002
	$		%	$		%	$		%

Tax at combined federal and
provincial rates	(7,870,820	)	39.92	2,962,000		41.20	1,350,000		42.37
Tax effect of:
Non-deductible expenses	1,198,057			1,929,000			898,400
Income not taxable	(43,080	)		(165,400	)		(70,500	)
Resource allowance	(1,343,458	)		(2,218,342	)		(1,021,197	)
Large corporation tax in excess of surtax	—			90,000			25,000
Effect of changes in tax rates	700,429			(386,130	)		—
Other	(77,003	)		—			—
	(7,435,875	)		2,211,128			1,181,703

F-16

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

8. NET (LOSS) EARNINGS PER SHARE

Basic net (loss) earnings per share were calculated on the basis of the weighted average number of shares outstanding for the year ended December 31, 2004 of 23,665,110 [year ended December 31, 2003 - 21,393,902; nine-months ended December 31, 2002 - 20,357,153]. The effect of any potential common share issuances in 2004 is anti-dilutive. The weighted average number of shares outstanding for the diluted calculation for the year ended December 31, 2003 was 21,947,801, and for the nine-months ended December 31, 2002 was 20,554,231.

	Year Ended		Year Ended	Nine Months Ended
	December 31,		December 31,	December 31,
	2004		2003	2002
	$		$	$

Numerator
Net (loss) earnings for the period	(12,280,609	)	4,978,302	2,004,306

Denominator
Weighted average number of common
shares outstanding	23,665,110		21,393,902	20,357,153
Effect of dilutive stock options	—		553,899	197,078
	23,665,110		21,947,801	20,554,231

Basic net (loss) earnings per share	(0.52	)	0.23	0.10
Diluted net (loss) earnings per share	(0.52	)	0.23	0.10

F-17

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

9. CHANGES IN NON-CASH WORKING CAPITAL BALANCES

[a]	Changes affecting operating activities comprise:

		Year Ended		Year Ended		Nine Months Ended
		December 31,		December 31,		December 31,
		2004		2003		2002
		$		$		$
	Accounts receivable	(932,140	)	1,299,019		(968,683	)
	Prepaid expenses	(4,829	)	(4,678	)	13,456
	Accounts payable and accrued liabilities	(2,713,405	)	3,111,979		2,155,188
	Income taxes payable (receivable)	(659,519	)	791,291		(553,132	)
		(4,309,893	)	5,197,611		646,829

[b]	Changes affecting investing activities comprise:

		Year Ended		Year Ended		Nine Months Ended
		December 31,		December 31,		December 31,
		2004		2003		2002
		$		$		$
	Accounts receivable	(212,934	)	(1,834,645	)	521,453
	Accounts payable and accrued liabilities	8,726,182		(2,909,877	)	5,367,343
		8,513,248		(4,744,522	)	5,888,796

10. FINANCIAL INSTRUMENTS

The Company’s financial instruments consist of accounts receivable, income taxes receivable, bank indebtedness, operating loan, accounts payable and income taxes payable. The carrying values of these financial instruments approximate their fair value.

The Company’s accounts receivable principally result from the sale of its various hydrocarbon commodities and from the collection of partner liabilities pursuant to joint venture agreements under which it has operatorship responsibilities. Substantially all of the Company’s accounts receivable at December 31, 2004, and 2003 are from other companies in the oil and gas industry. This concentration of customers may impact the Company’s overall credit risk, either positively or negatively, in that such entities may be similarly affected by industry-wide changes in economic or other conditions. Historically to date, the Company has not incurred credit losses against its receivables. At December 31, 2004 one customer and two joint venture partners represent 38% of the accounts receivable balance with totals of 16%, 11% and 11% respectively [December 31, 2003 - two customers represent 39% of accounts receivable with totals of 22% and 17% respectively].

F-18

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

11. RECONCILIATION TO U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The Company prepares its accounts in accordance with Canadian generally accepted accounting principles (Canadian GAAP), which for the most part, are similar to United States generally accepted accounting principles (U.S. GAAP). The following tables reflect the major differences in accounting principles.

Consolidated net (loss) earnings under U.S. GAAP would be:

	Year Ended		Year Ended		Nine Months Ended
	December 31,		December 31,		December 31,
	2004		2003		2002
	$		$		$

Net (loss) earnings under Canadian GAAP	(12,280,609	)	4,978,302		2,004,306
Amortization and depletion [a]	—		—		(65,471	)
Accretion of asset retirement obligation [a]	—		—		40,242
Options issued for services [b]	—		—		(3,108	)
Write-down on natural gas and oil
properties [c]	—		(125,580	)	(209,160	)
Net (loss) earnings before cumulative
effect of change in accounting principle
under U.S. GAAP	(12,280,609	)	4,852,722		1,766,809

Cumulative effect of change in accounting
principle, net of applicable taxes [a]	—		133,276		—

Net (loss) earnings under U.S. GAAP after
cumulative effect of change in accounting
principle	(12,280,609	)	4,985,998		1,766,809

Net (loss) earnings per common share under U.S. GAAP,
before change in accounting policy
- basic	(0.52	)	0.23		0.09
- diluted	(0.52	)	0.22		0.09

Net (loss) earnings per common share under U.S. GAAP,
after change in accounting policy
- basic	(0.52	)	0.23		0.09
- diluted	(0.52	)	0.23		0.09

F-19

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

11. RECONCILIATION TO U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

After certain differences have been adjusted for, selected balance sheet items under Canadian and U.S. GAAP would be:

	December 31				December 31
	2004				2003
	Canadian		U.S.		Canadian	U.S.
	GAAP		GAAP		GAAP	GAAP
	$		$		$	$

Natural gas and oil interests [c]	56,726,494		56,726,494		57,083,789	56,901,789
Share capital [b, d]	39,852,368		38,725,461		27,747,487	28,720,580
Accounts payable and
accrued liabilities [d]	17,348,723		19,448,723		11,335,946	11,335,946
(Deficit) retained earnings [a, b, c]	(9,455,298	)	(10,949,459	)	2,825,311	1,331,150

[a]	Asset retirement obligation

	During 2003, the Company early-adopted CICA Handbook section 3110 - “Asset Retirement Obligations” for Canadian GAAP and SFAS 143 - “Accounting for Asset Retirement Obligations” for U.S. GAAP. The transitional provisions differ between Canadian GAAP and U.S. GAAP in that Canadian GAAP requires restatement of comparative amounts whereas U.S. GAAP does not allow restatement, but rather requires a cumulative catch-up adjustment to earnings. An adjustment to net earnings under Canadian GAAP has been recorded to reflect the December 31, 2002 comparative amounts prior to restatement in accordance with U.S. GAAP.

[b]	Stock-based compensation

	In December 2004, FASB issued SFAS No. 123 (Revised), “Share-Based Payments”. This statement requires an entity to recognize the grant-date fair value of stock options and other equity-based compensation issued to employees in the statement of operations. SFAS 123 (Revised) eliminates the ability to account for share-based compensation transactions using the intrinsic value method in APB Opinion 25. The Company, effective January 1, 2003, early adopted FASB Statement No. 123, “Accounting for Stock-Based Compensation - Transition and Disclosure”. Accordingly, these revisions to SFAS No. 123 did not have a significant impact on the Company’s financial statements.

F-20

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

11. RECONCILIATION TO U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

[c]	Under both U.S. and Canadian GAAP, property, plant and equipment must be assessed for potential impairments. Under U.S. GAAP, if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, then an impairment loss (the amount by which the carrying amount of the asset exceeds the fair value of the asset) should be recognized. Fair value is calculated as the present value of estimated expected future cash flows. Prior to 2004, under Canadian GAAP, the impairment loss was recognized as the difference between the carrying value of the asset and its net recoverable amount (undiscounted). The Company has adopted a new standard effective for 2004 that has eliminated this U.S./Canadian GAAP difference.

[d]	For U.S. GAAP, the premium received by the Company on the issuance of flow-through shares which is in excess of the fair value of common shares is required to be credited to liabilities. The liability is reversed when tax benefits are renounced and a deferred tax liability is recognized in respect of renounced Canadian exploration expenses at that time. Any difference arising between the liability and deferred tax liability is accounted for as an income tax expense. During 2004, total flow-through share premium received was $2,100,000.

[e]	For U.S. GAAP, dry hole expenses of $10,166,601 for the year ended December 31, 2004 [year ended December 31, 2003 - $1,278,387; nine-month period ended December 31, 2002 - $325,478] included in investing activities on the statement of cash flows would be reported in operating activities. Under U.S. GAAP, separate subtotals within cash flow from operating activities are not presented.

12. COMMITMENTS

[a]	The Company has entered into an operating lease in respect of its office premises.

	The minimum payments under this lease commitment, including estimated operating costs are as follows:

		$

	2005	203,657
	2006	203,657
	2007	203,657
	2008	84,857
		695,828

F-21

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2004

12. COMMITMENTS (cont’d.)

[b]	As part of the Company’s flow through share financing [see note 6[a]], the Company is committed to renounce CEE in favour of the original holders of the flow through shares. The Company expects to renounce CEE of $11,200,000 in 2005[see note 14].

13. ECONOMIC DEPENDENCY

[a]	The St. Albert property in Alberta is a core property of the Company and the majority of gas production from the property is pipelined and processed through facilities owned and operated by Atco Midstream (“Atco”) of Calgary, Alberta.

	Effective November 1, 1997, the Company and its then joint interest partner, Fletcher Challenge Energy Canada Inc. signed a ten-year, firm service, sour gas processing and transportation agreement with Atco for a maximum daily quantity of 15 million cubic feet of gas per day to be processed at Atco’s Carbondale plant.

	Effective December 15, 1998, a similar agreement was signed by the partners and Atco to process sweet gas at Atco’s Villenueve plant, also for a maximum daily quantity of 15 million cubic feet of gas per day.

	Both agreements include an automatic renewal for a further ten years, subject to fee renegotiation.

[b]	During the year ended December 31, 2004, three customers accounted for 85% of the Company’s sales with totals of 45%, 30% and 10% respectively [year ended December 31, 2003 – three customers accounted for 82% of the Company’s sales with totals of 37%, 30% and 15% respectively; nine-month period ended December 31, 2002 – four customers accounted for 92% of the Company’s sales with totals of 35%, 33%, 13% and 11% respectively].

14. SUBSEQUENT EVENTS

On February 28, 2005, the Company officially renounced $11,200,000 of taxable benefits relating to qualifying expenses in favour of shareholders that participated in the flow-through private placement that closed on May 19, 2004. Such qualifying expenditures are specifically defined in the Income Tax Act (Canada). As at December 31, 2004, the Company had incurred approximately 67% of the qualifying expenditures and committed another 20% toward the required obligation. The remainder of the qualifying expenditures must be incurred by December 31, 2005.

F-22

INDEX TO EXHIBITS

Exhibit Numbers	EXHIBITS
1(a)	Certificate of Incorporation (1)
1(b)and 2(a)(i)	Notice of Articles and Articles (7)
1 (d) and 2(a)(iv)	Corporate Governance Committee Guidelines (3)
2 (a)(v)	Shareholder Rights Plan Agreement (2)
4 (i)	Sour Gas Processing and Transportation Agreement by and between ATCO Gas Services Ltd. And Fletcher Challenge Energy Canada and Dynamic Oil Limited, dated July 11, 1997 (1)
(ii)	Gas Purchase Contract by and between Dynamic Oil Limited and Progas Limited, dated November 1, 1997 (1)
(iii)	Sweet Gas Processing and Transportation Agreement between ATCO Gas Services Ltd. and Dynamic Oil & Gas Inc., dated December 16, 1998 (2)
(iv)	Purchase and Sale Agreement between Fletcher Challenge Oil & Gas Inc. and Dynamic Oil & Gas, Inc. et al, dated June 26, 2001 (re: acquisition of Fletcher’s interest in St. Albert property by Dynamic, Trioco Resources Inc. and Energy North Inc.) (4)
(v)	Contribution, Mutual Interest and Exclusion Agreement between Dynamic Oil & Gas, Inc., Trioco Resources Inc. and Energy North Inc. dated June 29, 2001 (re: Joint bidding agreement in connection with the Purchase and Sale Agreement of Fletcher’s St. Albert interest described above (4)
(vi)	Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas, Inc. and Wayne Babcock (4)
(vii)	Amended Schedule A, dated September 30, 2004, to the Employment Agreement between Dynamic Oil & Gas, Inc. and Wayne Babcock (7)
(viii)	Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas, Inc. and Donald K. Umbach (4)
(ix)	Amended Schedule A, dated September 30, 2004, to the Employment Agreement between Dynamic Oil & Gas, Inc. and Donald K. Umbach (7)
(x)	Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas, Inc. and Michael Bardell (4)
(xi)	Amended Schedule A, dated September 30, 2004, to the Employment Agreement between Dynamic Oil & Gas, Inc. and Michael Bardell (7)
(xii)	Employment Agreement, dated March 5, 2001 between Dynamic Oil & Gas, Inc. and David Grohs (4)
(xii)	Amended Schedule A, dated September 30, 2004, to the Employment Agreement between Dynamic Oil & Gas, Inc. and David Grohs (7)
(xiii)	Employment Agreement, dated March 12, 2001 between Dynamic Oil & Gas, Inc. and Jonathan White (4)
(xiv)	Amended Schedule A, dated September 30, 2004, to the Employment Agreement between Dynamic Oil & Gas, Inc. and Jonathan White (7)
(xv)	Underwriting Agreement dated May 19, 2004 between Dynamic Oil & Gas, Inc. and Octagon Capital Corporation and Raymond James Ltd. (7)

INDEX TO EXHIBITS continued

Exhibit Numbers	EXHIBITS

12.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer (7)
12.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer (7)
13.1	Section 1350, Certification of Chief Executive Officer (7)
13.2	Section 1350, Certification of Chief Financial Officer (7)
14	National Instrument 51-101, Canadian Standards of Disclosure for Oil and Gas Activities, Form 1, Form 2, and Form 3 (7)

Unless otherwise noted, each exhibit to this Report has been filed by us with previous Annual Reports under the exhibit number indicated in parentheses following that Exhibit reference and under the same Exhibit Number as filed herewith. All such Exhibits are incorporated by reference.

	(1)	Form 20-F Annual Report filed on September 30, 1997.
	(2)	Form 20-F Annual Report filed on September 9, 1999.
	(3)	Form 20-F Annual Report filed on August 16, 2000.
	(4)	Form 20-F Annual Report filed on August 15, 2001.
	(5)	Form 20-F Annual Report filed on August 19, 2002.
	(6)	Form 20-F Annual Report filed on May 19, 2004
	(7)	Filed herewith.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Good

Dynamic Oil & Gas (DYOLF) Inactive 20-F2004 FY Annual report (foreign)

Content analysis