Dynamic Oil & Gas 20F 2002 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

OR

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

OR

	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the transition period April 1, 2002 to December 31, 2002

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)

205 - 10711 Cambie Road
Richmond, British Columbia V6X 3G5, 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

Indicate the number of outstanding shares of each of the Issuer’s classes of capital or common stock as of the close of the period covered by the Annual Report:

Title of Each Class	Outstanding at December 31, 2002
Common Stock Without Par Value	20,272,530 Shares

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

Indicate by check mark which financial statement item the Company 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.........................................	6

Item 2.	Offer Statistics and Expected Timetable...................................................................	6

Item 3.	Key Information..........................................................................................................	6

Item 4.	Our Information..........................................................................................................	14

Item 5.	Operating and Financial Review and Prospects........................................................	33

Item 6.	Directors, Senior Management and Employees.......................................................	46

Item 7.	Major Shareholders and Related Party Transactions..............................................	56

Item 8.	Financial Information.................................................................................................	56

Item 9.	The Offer and Listing.................................................................................................	57

Item 10.	Additional Information...............................................................................................	58

Item 11.	Quantitative and Qualitative Disclosures About Market Risk...............................	66

Item 12.	Description of Securities Other than Equity Securities...........................................	69


Part II.

Item 13.	Defaults, Dividend Arrearages and Delinquencies..................................................	69

Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds...	69

Item 15.	Controls and Procedures............................................................................................	69

Item 16.	[Reserved]...................................................................................................................	70

Item 16(A).	Audit Committee Financial Expert.............................................................................	70

Item 16(B).	Code of Ethics.............................................................................................................	70

Item 16(C).	Principal Accountant Fees and Services....................................................................	70



Part III.

Item 17.	Financial Statements...................................................................................................	70

Item 18.	Financial Statements...................................................................................................	71

Item 19.	Exhibits.........................................................................................................................	71

Glossary of Terms

Air drilling	A method of drilling that uses compressed air as a medium for transporting drill cuttings to surface.

Basal Quartz zone	A name generally applied to the Ellerslie formation as it occupies the “bottom” sandstone of the Mannville Group 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.

Blairmore formation	Formation encompassing clastic sediments deposited in the Early Cretaceous Age from about 100 to 120 million years ago.

Blue Sky formation	Sandstones of the Lower Cretaceous, 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.

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.

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 (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 Mannville 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 90^o) 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 Winterburn Group of the Upper Devonian Age, 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 Woodbend Group of the Upper Devonian Age, 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 rocks.

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 production rate of a group of gas wells.

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.

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.

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 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 C5H12 and 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.

Probable reserves	Those reserves that analysis of drilling, geological, geophysical and engineering data do not demonstrate to be proved with current technology and under existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable reserves to be obtained will be the increased recovery beyond estimated proved reserves that can be realistically estimated for the pool through enhanced recovery processes that can reasonably be expected to be instituted in the future.

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.

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.

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 90^o.

Viking gas well	A well capable of commercial gas production from the Upper Cretaceous Viking sands deposited about 97.5 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 net production revenues.

Part I.

Prior to this filing, our most recently filed annual report covered the twelve-month period ended March 31, 2002. Since then, we changed our fiscal year end to December 31. This report covers the nine-month transition period from April 1, 2002 to December 31, 2002. Where useful for comparison purposes, annualized numbers are presented by applying the nine-month transition numbers multiplied by four-thirds. However, this method does not reflect actual results for the three-month extrapolated period and such results may differ from the result achieved by this calculation. Also, for ease of reading, we may refer to nine-month period ended December 31, 2002 as “Nine-Month Fiscal Transition 2002”; the 12-month period ended March 31, 2002 as “Fiscal 2002”; and the 12-month period ended March 31, 2001 as “Fiscal 2001”.

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 Transition 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 in Item 17 in this Transition Report are also prepared under Canadian GAAP. Included in Note 12 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 Transition Report, all references to dollars are to Canadian dollars.

Selected Financial Data Presented According to Canadian GAAP


	As at
	December 31				As at March 31

($ 000’s)	2002		2002		2001		2000		1999

Balance Sheets
Working capital (deficiency)	(16,818	)	(13,281	)	1,969		(3,716	)	(1,225	)
Total assets	43,647		37,152		29,991		18,811		12,487
Current liabilities	23,729		19,625		6,210		7,717		3,950
Long-term liabilities	991		824		540		402		404
Deferred gain on sale	-		109		340		652		997
Future income tax liability	682		-		2,955		-		-
Net assets	18,245		16,593		19,947		10,041		7,136
Share capital	20,721		20,915		20,642		20,420		21,080
Deficit	(2,476	)	(4,322	)	(695	)	(10,379	)	(13,944	)


	Nine-Month
	Fiscal
	Transition	For the 12-month period ended March 31

($ 000’s)	2002	2002		2001	2000	1999

Statements of Operations
Gross revenues	24,123	26,402		34,463	15,770	9,495
Net revenues	13,309	14,215		20,524	7,438	3,857
Cash flow from operations¹	10,723	11,337		18,168	5,634	2,634
Cash flow per share, basic ($)	0.53	0.55		0.91	0.29	0.13
Cash flow per share, diluted ($)	0.52	0.55		0.89	0.28	0.13
Earnings (loss) before taxes	3,146	(5,419	)	14,449	2,871	1,212
Net earnings (loss)	1,978	(3,519	)	9,714	4,079	1,212
Common shares – weighted avg. (# 000’s)	20,357	20,365		19,938	19,710	19,892
Net (loss) earnings per share, basic ($)	0.10	(0.17	)	0.49	0.21	0.06
Net (loss) earnings per share, diluted ($)	0.10	(0.17	)	0.48	0.20	0.06

⁽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
	Fiscal
	Transition		%		Fiscal	%
($ 000’s)	2002		Chg		2002	Chg		Fiscal 2001

Cash flow from operating activities (GAAP measure)	11,370		16		9,779	(49	)	19,264
Changes in non-cash working capital (GAAP measure)	(647	)	(142	)	1,559	242		(1,096	)

Cash flow from operations (non-GAAP measure)	10,723		(5	)	11,337	(38	)	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
	December 31				As at March 31

($ 000’s)	2002		2002		2001		2000		1999


After adjusting for certain differences, selected balance sheet items under U.S. GAAP would become:

Balance Sheets
Future income tax asset	-		371		-		242		-
Future income tax liability	541		-		3,532		-		-
Natural gas and oil interests	36,236		30,150		21,679		13,721		9,702
Share capital*	21,694		21,883		21,610		21,368		21,802
Deficit	(1,640	)	(5,422	)	(2,356	)	(11,473	)	(14,896	)

*	For further explanation of the reconciling adjustments shown below, see Note 12 attached to the Financial Statements presented under Item 17 to this Transition Report.


	Nine-Month
	Fiscal
	Transition		For the 12-month period ended March 31

($ 000’s)	2002		2002		2001		2000		1999

Statements of Operations
Net (loss) earnings under Canadian GAAP	1,978		(3,519	)	9,714		4,079		1,212
Reconciling adjustments*
Compensatory stock options issued	-		-		-		-		(8	)
Options issued for services	(5	)	-		(20	)	-		-
Ceiling test adjustment to natural gas properties	(332	)	(216	)	-		(145	)	-
Income taxes	141		669		(577	)	-		-
Net (loss) earnings under U.S. GAAP	1,782		(3,066	)	9,117		3,934		1,204
Net (loss) earnings/share, U.S. GAAP basic ($)	0.09		(0.15	)	0.46		0.20		0.06
Net (loss) earnings/share, U.S. GAAP diluted ($)	0.09		(0.15	)	0.45		0.19		0.06

Dividends

We have never paid or declared dividends on our shares of common stock and we do not intend to do so in the foreseeable future. We intend to use our retained earnings to finance growth.

Exchange Rates

Our financial statements, as provided under Items 8 and 17, are presented in Canadian dollars. For comparison purposes, exchange rates into U.S. dollars (the host country currency) 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 May 5, 2003 was CDN $1.4134 per U.S. $1.00.

Exchange Rates for Canadian Versus U.S. Dollars
(High/low rates for latest six months)	High	Low

April, 2003	1.4843	1.4336
March, 2003	1.4905	1.4659
February, 2003	1.5303	1.4928
January, 2003	1.5750	1.5220
December, 2002	1.5800	1.5478
November , 2002	1.5903	1.5528

Exchange Rates for Canadian Versus U.S. Dollars
		Average ($)

For the nine-month period ended December 31
2002		1.56
For the twelve-month periods ended March 31
2002		1.57
2001		1.50
2000		1.47
1999		1.50

Capitalization and Indebtedness

Not applicable.

Reasons for the Offer and Use of Proceeds

Not applicable.

Risk Factors

Business Risk Management

The natural gas and oil industry is highly competitive, particularly in the following areas:

	•	searching for and developing new reserves of natural gas and crude oil;
	•	constructing pipelines and facilities required to transport or process produced commodities, and
	•	operating facilities related to the production of natural gas and crude oil.

Our competitors include major integrated oil and gas companies and numerous other independent oil and gas companies.

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.

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. Significant competition 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.

Dependence on Third Party Pipelines

In Nine-Month Fiscal Transition 2002, 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.

Operating History and Significant Historical Operating Losses

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. Due to the relatively short five-year production history from the majority of wells on the property, 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 returned to a loss of $3,519,085. In Nine-Month Fiscal Transition 2002, we again reported earnings of $1,977,663. As at December 31, 2002, we had an accumulated deficit of $2,475,932. 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 Key Personnel

Our success depends in large part on the personal efforts of our President & Chief Executive Officer, Wayne J. Babcock, our Vice President & Chief Operating Officer, Donald K. Umbach, our Vice President of Exploration, James R. Britton, our Vice-President of Operations, David G. Grohs and our Chief Financial Officer & Corporate Secretary, Michael A. Bardell. The loss of the services of any of these persons could have a material adverse effect on us.

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.

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.

Dependence on One Major Property

Currently, our major producing asset is our property located at St. Albert, Alberta. While the St. Albert property as of December 31, 2002 has developed into 16 separate, mutually-exclusive oil and gas pools stacked in 7 productive formations (4 natural gas and 3 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 to continue to produce enough cash flow, along with our bank credit facility, to support land acquisitions, drilling operations, facilities construction and general /administration costs. At this time, we believe that our cash flow and credit facility will be sufficient to support our business activities without securing significant additional financing in the near future. If it were to become necessary to raise significant additional financing, any arrangements that may be entered into could be expensive to us. 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 "Operating and Financial Review and Prospects" for a discussion of our capital budget).

We expect to continue using our bank credit facility to borrow funds 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 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 arranging substitute financing. For a description of our bank credit facility and its principal terms and conditions, see "Operating and Financial Review and Prospects” under Item 5, and Note 4 attached to the Financial Statements under Item 17 of this Transition Report.

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, 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.

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.

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, 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.

Operating Risk

Exploring and developing for natural gas and crude oil involves many risks, some of which are:

	•	unexpected formations or pressures;
	•	equipment failures and other accidents;
	•	uncontrolled hydrocarbon releases;
	•	adverse weather conditions;
	•	government and political actions;
	•	premature reservoir declines, and
	•	environmental impacts.

Although we maintain customary industry insurance, we cannot fully insure against all of these risks. Losses resulting from the occurrence of these risks could have a material adverse impact.

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.

Drilling Plans Subject to Change

This Transition 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 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.

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 and income, 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.

Dependence on Few Customers

During Nine-Month Fiscal Transition 2002, our natural gas sales were sold to three customers and, our natural gas liquids and crude oil between three customers who are different than our natural gas customers. We do not believe that the loss of one of our customers would have a material adverse effect on us because of the availability of other customers willing or interested in purchasing our products.

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 regulation 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.

Our reserve estimates and net present values reported in the Review of Operations section of this Transition Report are based on estimated constant commodity prices and associated production costs as of the estimate date. Actual future prices and costs may be materially higher or lower.

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.

Restoration, Safety and Environmental Risk

All our operations are in western Canada and, in particular, the western provinces of Alberta and British Columbia. 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 liability on us for remedial and clean-up costs, personal injuries related to safety and environmental damages.

To ensure that we provide for future estimated removal and site restoration costs, we recognized $0.2 million in our Statement of Operations and Deficit during Nine-Month Fiscal Transition 2002, bringing our total recognized amount in our December 31, 2002 Balance Sheet to $1.0 million. We engage independent engineering consultants to assist in assessing our total future liabilities 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 $2.1 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. Consistent with our growth in other areas, we seek opportunities for performance improvement in our operating practices.

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 and The Petroleum and Natural Gas Act of British Columbia.

Kyoto Protocol Risk

The Kyoto Protocol treaty (Protocol) was established to reduce emissions of greenhouse gases (GHG) that are believed to contribute to increasing Earth’s surface temperatures and affecting the global climate change. Canada adopted the Kyoto Protocol in December 1997. The Protocol establishes commitments to reduce GHG internationally and Canada has committed to meet a 6% reduction over base-year 1990 during the period 2008 to 2012. While we believe we are a low-emission producer, it is not possible for us 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.

Interruption From Severe Weather

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

Competition

The natural gas and oil industry is highly competitive. We experience competition in all aspects of our business, including acquiring reserves, leases, licenses and concessions, 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 ours 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 or 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.

Item 4. Our Information

Our History and Development

Dynamic Oil & Gas, Inc. (formerly Dynamic Oil Limited) was incorporated under the Company Act of the Province of British Columbia, Canada on March 27, 1979. We have one wholly-owned, inactive subsidiary incorporated in Texas, called Seabird Oil & Gas, Inc.

Our principal executive office is located in rented space at Suite 205-10711 Cambie Road, Richmond, British Columbia V6X 3G5 Canada until May 26, 2003; after which date, our rented space will be at Suite 230-10991 Shellbridge Way, Richmond, British Columbia V6X 3C6. Our telephone number will remain (800) 663-8072.

Principal Capital Expenditures and Exploration Expenses Over the Past Three Reporting Periods

Capital Expenditures

Over the past three reporting periods our capital expenditures aggregated $46.3 million, an amount that is broken down by reporting period and spending category in the following table.

	Nine-Month Fiscal	%			%
($000’s)	Transition 2002	chg		Fiscal 2002	chg		Fiscal 2001

Drilling, completions, tie-ins	9,146	19		7,678	106		6,939
Facilities	780	(56	)	1,757	(50	)	3,522
Land acquisitions	2,568	(80	)	12,560	1105		1,042
Corporate office	84	(28	)	116	47		79

Total	12,578	(43	)	22,111	91		11,582

In the table above, the total aggregated amount of $46.3 million is itemized further by reporting period as follows:

Nine-Month Fiscal Transition 2002
Our capital expenditures were $12.6 million in Nine-Month Fiscal Transition 2002, a 43% decrease from the amount invested in Fiscal 2002. The main reason for this decrease was due to the acquisition of additional working interests at St. Albert during Fiscal 2002 that were not repeated in Nine-Month Fiscal Transition 2002. In Nine-Month Fiscal Transition 2002, we invested as follows:

	•	48% in Alberta development properties to maintain and grow existing production levels; and
	•	52% in British Columbia exploration properties for potential longer-term production growth.

	We invested our capital in the following specific areas:
	*Alberta*
	•	Exploration - drilling, completions and tie-ins totalled $0.2 million, most of which was spent at Halkirk;

	•	Development of core properties – drilling, completions and tie-ins totalled $3.9 million, 74% of which was spent at St. Albert and 26% at Halkirk;
	•	Facilities - $0.8 million to acquire an increased interest in gas processing facilities at St. Albert pursuant to a Sale and Leaseback arrangement, as described in Note 5 to our Financial Statements; and
	•	Land – acquisitions totalled $1.2 million, 94% of which was to purchase various working and royalty interests at St. Albert.
	*British Columbia*
	•	Exploration – drilling, completions and tie-ins totaled $5.0 million, all of which was spent in the Cypress/Chowade area; and
	•	Land - acquisitions totalled $1.4 million, 90% of which was spent at Orion.

	Fiscal 2002
	We invested our capital in the following specific areas:
	*Alberta*
	•	Exploration and Development – drilling, completions and tie-ins totalled $7.7 million, of which 95% was spent at St. Albert; and
	•	Facilities and Land – totalled $14.4 million, most of which was spent to acquire additional working interests at St. Albert.

	Fiscal 2001
	We invested our capital in the following specific areas:
	*Alberta*
	•	Exploration and Development – drilling, completions and tie-ins totaled $5.7 million, 53% of which was spent at St. Albert and the balance at Peavey/Morinville; and
	•	Facilities and Land – totalled $4.6 million, most of which was spent at Peavey/Morinville and Halkirk.
	*British Columbia*
	•	Exploration and Development – drilling, completions and tie-ins totalled $1.3 million, all of which was spent at Orion.

Exploration Expenses

Our Exploration Expenses are mainly comprised of costs for seismic, new property investigations and unsuccessful drilling attempts. Under our ‘successful efforts’ accounting policy, we reclassify costs for unsuccessful drilling attempts from capital expenditures to exploration expenses. Over the past three reporting periods our exploration expenses aggregated $7.9 million, an amount that is broken down by reporting period and spending category in the following table.

	Nine Month Fiscal	%			%
($ 000’s)	Transition 2002	chg		Fiscal 2002	chg		Fiscal 2001

Drilling	325	(91	)	3,821	472		668
Seismic data activity	847	31		649	(41	)	1,102
Other	187	6		176	14		153

Total	1,359	(71	)	4,646	142		1,923

In the table above, the total aggregated amount of $7.9 million is itemized further as follows:

	•	$4.8 million on unsuccessful drilling attempts;
	•	$2.6 million on conducting seismic surveys or acquiring seismic survey data; and
	•	$0.5 million on investigating new properties.

Capital Expenditures and Exploration Expenses Anticipated in 2003

The capital portion of our 2003 budget is $23.7 million. We plan to invest this capital as follows:

	•	$8.7 million or 37% in Alberta to maintain and grow production levels on existing core properties;
	•	$4.8 million or 20% in British Columbia to bring into production a new core property;
	•	$2.8 million or 12% in Alberta to explore for new reserves;
	•	$6.5 million or 27% in British Columbia to explore new frontier properties; and
	•	$0.9 million or 4% other.

Of the total budget amount, $10.8 million is for drilling, $6.1 million for new land acquisitions, $5.4 million for completions and tie-ins and $1.4 million for facilities.

Our drilling program for 2003 includes 20 wells, 14 of which are new and six re-entries. Of the 14 new wells, seven are planned for exploratory work in northeast British Columbia, three for exploratory and four for development work in Alberta.

This program is consistent with our strategy to grow reserves and production through the drill bit and is our largest-ever capital spending budget.

The exploration expense portion of our 2003 budget is $2.8 million. It is for the acquisition of 3D and 2D seismic data in areas of Alberta and British Columbia as yet to be resolved.

We expect funds for our capital expenditure and exploration expense plans for 2003 to be sourced from cash flow from our operations and from our bank credit facility (see Note 4 to the Financial Statements under Item 17 in this Transition Report and Liquidity and Capital Resources under Item 5). In the event that our funding sources are insufficient to accomplish the expenditure and exploration plans for 2003, we will be forced to curtail certain of such expenditures.

Recent Material Events

We have no recent material events to report.

Share Repurchases

During the last three reporting periods, we spent $0.7 million on the re-purchase and cancellation of over 0.4 million of our outstanding shares of common stock at prices ranging from $1.54 to $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.

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 earnings will be 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 pertaining to the transporting, marketing and exporting of 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 Nine-Month Fiscal Transition 2002, 85% came from the St. Albert property. The remainder originated from six other Alberta fields: Halkirk, Peavey/Morinville, Alexander, Simonette, Stanmore and Westlock. In Fiscal 2002, 84% of our production came from the St. Albert field, while the remainder came from six other fields: Peavey/Morinville, Halkirk, Westlock, Simonette and Stanmore. In Fiscal 2001, 82% of our production came from the St. Albert field, while the remainder originated from five other fields: Peavey/Morinville, Westlock, Simonette, Redwater and Stanmore.

Revenue Breakdown

Our total revenue for the past three reporting periods was $85.0 million. Of this total, 78% came from the sales of natural gas, 17% came from the sales of natural gas liquids and 5% came from the sales of crude oil. Additionally, virtually all of such revenue originated from our properties and interests in the Province of Alberta. The breakdown for each of the past three reporting periods is shown in the table below:

Natural Gas, Natural Gas Liquids and Crude Oil Revenue

The following table shows our natural gas, natural gas liquids and crude oil revenue for the periods presented.

	Nine Month Fiscal	%			%
($ 000’s)	Transition 2002	chg		Fiscal 2002	chg		Fiscal 2001

Natural gas	17,058	(19	)	20,944	(25	)	28,006
Natural gas liquids	4,012	(10	)	4,442	(25	)	5,935
Crude oil	3,053	200		1,016	95		522

Total	24,123	(9	)	26,402	(23	)	34,463

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 Nine-Month Fiscal Transition 2002, we sold 51% of our natural gas to ProGas and 49% into the AECO daily spot market. During Fiscals 2002 and 2001, we sold 53% and 77% to ProGas, respectively, and the balances to AECO.

Natural gas liquids and crude oil -We market our natural gas liquids and crude oil based on monthly prices posted by the major purchasers at Edmonton, Alberta. These prices correlate closely to the price of West Texas Intermediate, allowing for quality adjustments and location 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 within 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

Presently, we regularly compete with other companies in bidding for the acquisition of petroleum interests from the Alberta and British Columbia 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, in the 2002 Canadian Energy Survey of 2001 Results prepared by PriceWaterhouseCoopers, we ranked thirty-sixth and thirty-fifth in size out of one hundred Canadian exploration and production companies according to gross revenues and cash flow from operations, respectively.

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 within 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 commencement of drilling operations;
	•	the proximity of hydrocarbon pipelines or other economically-feasible transportation;
	•	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 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:

Central Alberta		British Columbia	Southern Saskatchewan

St. Albert	Stanmore	Cypress (northeastern B.C.)	Elmore
Halkirk	Westlock	Orion (northeastern B.C.)	Rapdan
Peavey/Morinville	Quirk Creek	Fraser Valley (southwestern B.C.)
Alexander	Wimborne
Simonette

Our total land holdings increased during the year by a net of 41,917 gross acres (24,493 net) or 28%, to 192,088 gross acres (110,744 net). This increase was spread among three key properties, Wimborne in Alberta, and Cypress/Chowade and Orion in British Columbia. Of our total land interests, 161,918 gross acres (90,496 net) were undeveloped. Our weighted average working interests of all our Alberta properties was 72% versus 52% in British Columbia. In total, our weighted average working interests increased by 1%, to 58%. The remaining 42% was held by joint venture, industry partners, who share a common interest in exploring or developing the properties in question.

We expect to continue to diversify and strengthen our land holdings in fiscal 2003.

Land Holdings (acres)
As at December 31, 2002

	Developed		Undeveloped		Total		Weighted
Area	Gross	Net	Gross	Net	Gross	Net	Avg WI %⁽¹⁾

Alberta
St. Albert	9,379	6,101	5,372	3,936	14,751	10,037	68%
Halkirk	3,840	3,456	3,200	3,182	7,040	6,638	94%
Peavey/Morinville	7,203	4,931	5,069	3,758	12,272	8,689	71%
Quirk Creek	640	320	10,720	5,360	11,360	5,680	50%
Wimborne	-	-	3,200	3,200	3,200	3,200	100%
Other	3,689	2,731	3,360	3,072	7,049	5,803	82%

	24,751	17,539	30,921	22,508	55,672	40,047	72%

British Columbia
Cypress/Chowade	3,499	1,749	12,010	4,028	15,509	5,777	37%
Orion	1,920	960	64,485	45,682	66,405	46,642	70%
Fraser Valley	-	-	54,502	18,278	54,502	18,278	34%

	5,419	2,709	130,997	67,988	136,416	70,697	52%

Total to Dec 31, 2002	30,170	20,248	161,918	90,496	192,088	110,744	58%
Total to Mar 31, 2002	24,110	17,089	126,061	69,162	150,171	86,251	57%

Increase (decrease)	6,060	3,159	35,857	21,334	41,917	24,493	1%
Increase (decrease) %	25%	18%	28%	31%	28%	28%	1%

⁽¹⁾	WI% means our net working interest through joint venture participation.

In Fiscal 2002 and Fiscal 2001, our total developed acreage comprised 24,110/18,175 gross acres and 17,089/11,078 net acres, respectively, while our total undeveloped acreage comprised 126,061/126,271 gross acres and 69,162/78,949 net acres, respectively. Our weighted average working interest in all properties in Fiscal 2002 and Fiscal 2001 was 57% and 63%, respectively.

				Future
	Percentage		New	Prospects		2003⁽⁴⁾
	Of		Frontier	For	Reserves	Activity
	Production⁽¹⁾	Core⁽²⁾	Exploration⁽³⁾	Development	Established	Planned

Alberta
St. Albert	85	x		x	x	x
Halkirk	7	x		x	x	x
Peavey/Morinville	3				x
Alexander	2				x
Simonette	1				x
Stanmore	1				x
Westlock	1				x
Quirk Creek			x	x
Wimborne				x		x

	100

British Columbia
Cypress/Chowade		x	x	x	x	x
Orion			x	x		x
Fraser Valley			x	x

⁽¹⁾	Based on total production during Nine-Month Fiscal Transition 2002.
⁽²⁾	Core properties are those that presently provide or are expected to provide a significant portion of new cash flows.
⁽³⁾	New frontier exploration represents those properties having no current production and are remote from current known production sources.
⁽⁴⁾	For details of 2003 planned activity, see “OUTLOOK FOR 2003”.

Using the property names as shown in the above table, details of each property as to its location, geological description, land holdings, wells and facilities, key development activities achieved during Nine-Month Fiscal Transition 2002 and our plans for 2003 are described below. Maps are also included to help show the physical location of each property.

Alberta Properties

St. Albert	•	St. Albert is located in central Alberta near the City of Edmonton.

Geological Description	•	St Albert is comprised of sixteen separate Cretaceous-aged natural gas and Devonian-aged crude oil pools stacked in seven productive formations, four natural gas and three crude oil. We consider the St. Albert property as several core properties in one, as this high concentration of pools in one property is industry unique.
	•	Historically, the property has produced in excess of 22.5 million barrels of crude oil and 109 billion cubic feet of raw natural gas.
	•	The area is prospective for remaining recoverable crude oil from six established pools in the Leduc (D-3), Nisku (D-2) and Wabamun (D-1) formations.

Land holdings	•	We hold 14,751 acres (10,037 net) under lease.

Wells and facilities	•	We own a 75% working interest (WI) in 22 producing natural gas wells;
	•	Our ownership ranges from 44% to 77% WI in four producing natural gas wells.
	•	We own a 75% WI in eight producing crude oil wells;
	•	We own a 75% WI in one oil facility (battery), one solution gas plant, one sour gas compressor, two sweet gas compressors and a 13-km , 6” sour gas pipeline.

Operating activities	•	We drilled a successful D-3 oil well (location 06-25) by re-entering a previously suspended well bore, cutting a window in the casing below the Mannville formation and directionally drilling to a new seismically identified bottom hole location.
	•	The oil well (location 06-25) confirmed our long-held belief that commercial quantities of D-3 oil reserves remained trapped in an attic position within the reef above production that exists from original, 1950’s-vintage vertical wells.

	•	During the initial eight-hour production test of the 06-25 well, it flowed at an average rate of 990 boe/d and averaged 498 boe/d in 61 operating days.
	•	We drilled a successful Ostracod A natural gas well at 07-26.
	•	We drilled a successful well targeting crude oil in the Nisku (D-2) formation at 12-25. An oil well re-completion was successful in the Wabamun (D-1) formation at 10-36.
	•	Drilling and completion activity increased the production of oil and natural gas liquids during Nine-Month Fiscal Transition 2002 by an average of 259 boe/d or 37%, to 959 boe/d over Fiscal 2002.
	•	Natural gas production declined during Nine-Month Fiscal Transition 2002 by an average of 124 boe/d or 6%, to 1,893 boe/d over Fiscal 2002, in response to an expected decline in reservoir pressure.
	•	In total, we increased our average daily production rates at St. Albert in Nine-Month Fiscal Transition 2002 by a net of 135 boe/d or 5%, to 3,852 boe/d over the previous twelve-month period to a daily average of 2,852 boe/d.
	•	Overall, reserves and production at St. Albert were added while minimizing surface and environmental impact by re-entering existing well bores and surface facilities.

Looking ahead to 2003	•	We have identified several drilling targets prospective for incremental crude oil and natural gas recovery.
	•	We have budgeted eight new wells at St. Albert in 2003, six targeting remaining crude oil potential in established pools and two targeting accelerated natural gas production from the Ostracod A pool.
	•	We plan to address declining reservoir pressures in various natural gas pools by adding third-party compression at the inlet to processing facilities located at Villenueve and Carbondale gas plants.

Halkirk	•	Halkirk is in central Alberta approximately 168 kilometers (kms) northeast of Calgary.

Geological description	•	This area is prospective for multiple, sweet natural gas-bearing Cretaceous-aged sandstone reservoirs.
	•	The primary target for reserves is the Viking “C” sand with an average net pay thickness of approximately five meters.

Land holdings	•	We have 7,040 gross acres (6,638 net) under lease.

Wells and facilities	•	We own a 100% WI in four producing gas wells and one suspended well.
	•	We also own an 80% WI BPO (before payout) and a 48% WI APO (after payout) in three producing gas wells.
	•	All our natural gas production is processed at the Maple Glen Refrigeration Plant under a third-party custom processing agreement.

Operating activities	•	We drilled one successful Viking C natural gas well at location 12-30 and successfully re-completed a previously abandoned well bore in the Viking C sand at location 6-24.
	•	We conducted several work-over operations on existing wells during Nine-Month Fiscal Transition 2002.
	•	Production of natural gas and natural gas liquids decreased in Nine-Month Fiscal Transition 2002 by 32 boe or 10%, to 288 boe/d on an operating day basis over Fiscal 2002 reflecting an expected decrease in reservoir pressure and tight reservoir permeability in the Viking C sand.
	•	To date, our reserves at Halkirk are based on a 320-acre drainage area; in the future we will need to drill infill wells to increase reserve allocations.


Looking ahead to 2003	•	We expect to maintain current production rates by drilling two infill wells in 2003 and adding third-party compression services at the Maple Glen gas plant.

Wimborne	•	Wimborne is located in south-central Alberta approximately 112 kms northeast of Calgary.

Geological description	•	This area is prospective for multiple Cretaceous-aged sandstone reservoirs containing natural gas and natural gas liquids.
	•	Additional potential exists for crude oil and natural gas within deeper Mississippian carbonate reservoirs in the Pekisko formation.

Wells and facilities	•	We have not drilled any wells to date.
	•	The property is in close proximity to existing natural gas pipelines and processing facilities.

Land Holdings	•·	We own 3,200 gross acres (3,200 net) of petroleum and natural gas (P&NG) rights.

Operating activities	•	During the period, we participated in a large multi-client 3D seismic shoot and conducted our own 3D proprietary seismic program. In total, we shot or acquired over 160 kms²of high quality 3D seismic, a database that is expected to provide a long-term exploration and development strategy for the area.
	•	We acquired a 100% WI in one new section (640 acres) of crown P&NG lands.

Looking ahead to 2003	•	Since December 31, 2002, we acquired 4,480 gross acres (4,480 net) of new crown P&NG leases.
	•	We have identified through seismic up to 12 exploration and development targets on our lands, and plan to drill three exploration wells in 2003.
British Columbia Properties

Cypress/Chowade	•	Cypess/Chowade is located in the foothills of northern British Columbia approximately 100 kms northwest of Fort St. John.

Geological description	•	The area is prospective for multiple, natural gas-bearing Triassic sandstone and deep Mississippian carbonate reservoirs contained within classic foothill anticlines that trend northwest-southeast through the area.

Land holdings	•	We have under lease 15,509 gross acres (5,779 net).

Wells and facilities	•	In four wells, we own a 50% BPO-30% APO WI and in one other well, we own a 50% WI, both BPO and APO.
	•	A major expansion of pipeline and processing is required.

Operating activities	•	We participated in drilling five exploration wells under two, separate farmin agreements targeting multi-zone natural gas bearing reservoirs of Triassic age. All five wells were cased as new-pool natural gas discoveries.
	•	Initial independent estimates of productivity from the five wells is in excess of 20 mmcf/d (10 mmcf/d net to us), based on drill-stem and production testing.

Looking ahead to 2003	•	Natural gas discoveries to date justify the partnership to finance a major expansion of existing natural gas production and transportation facilities.
	•	We expect to have two wells on stream during the summer and three more on by late fall 2003.
	•	We have assembled a large, 2D seismic database on our lands and have mapped multiple prospect fairways on which the land strategy was based. We have seismically identified more than 20 potential exploration and development locations.
	•	We plan to drill up to six outpost wells in 2003, three exploratory and three development.
	•	Since December 31, 2002, we have acquired a total of 24,100 gross acres (7,799 net) of P&NG rights at two separate crown land sales. This brings our total land holdings to 36,609 gross acres (13,467 net).
	•	We plan to continue an aggressive land acquisition strategy under an expanded area of mutual interest with our two industry partners, encompassing approximately 750,000 gross acres.


Orion		Orion is strategically located between the Sierra and Helmet natural gas fields approximately 56 kms west of the Alberta border and 112 kms south of the Northwest Territories border. The property is dissected by the Sierra Yoyo Desan Road, which provides year-round access for drilling operations.

Geological description	•	The area is prospective for natural gas exploration and development in the Jean Marie, Bluesky, Debolt and deeper Slave Point formations.

Land holdings	•	We hold under lease 66,405 gross acres (46,642 net).

Wells and facilities	•	We own a 100% WI in onepotential Bluesky and onehorizontal Jean Marie natural gas well.
	•	In one horizontal Jean Marie potential natural gas well we own a 15% gross overriding BPO and a 50% WI APO.
	•	Our property is located at the termination of two major pipeline systems. The Duke Energy Pipeline System connects to Fort Nelson for delivery to Washington State and the Duke Energy Field Services Pipeline System connects to Tooga Compressor Station for delivery to Alberta. Both pipelines are approximately seven kms from our property.

Operating activities	•	A horizontal well was drilled and completed as a potential Jean Marie natural gas well. The well was drilled by our large, independent Canadian oil and gas partner pursuant to a farmin agreement.
	•	We pursued an aggressive land acquisition program by adding 36,401 gross acres (23,308 net) of P&NG leases. Approximately 59% of our lands are owned by Dynamic (50%) and its partner. We own 100% working interest in the balance.

Looking ahead to 2003	•	A large independent Canadian oil and gas company has used the term, ‘The Greater Sierra Gas Play’ to refer to the regional Jean Marie, and has described the area as the largest gas play discovered in Western Canada. Our lands form a part of the area and are a key element in our long-term growth strategy.
	•	We plan to drill one horizontal exploration test well into the Jean Marie formation and shoot 90 kms²of proprietary 3D seismic in 2003 in preparation for future drilling.

Fraser Valley		The property is located in the Lower Mainland area of southwest British Columbia near the port City of Vancouver.

Land holdings	•	Under a joint venture agreement with Conoco Canada Limited, we continue to hold approximately 54,502 gross acres (18,278 net) of onshore and offshore P&NG rights associated with Permit 802, a validated British Columbia Exploration Permit.
	•	Permit 802 is under Provincial jurisdiction and includes offshore P&NG rights in the Georgia Basin, located in the Strait of Georgia between the Lower Mainland and Vancouver Island.

Looking ahead to 2003	•	Presently, areas offshore are subject to a restricted access moratorium for petroleum and natural gas activities; however, discussions are underway between the Provincial and Federal Governments in regards to lifting the moratorium. The Provincial Government has indicated its desire to move forward and the Federal Government is currently conducting a public review to identify environmental and social concerns arising from offshore activities along the Pacific West Coast. A final decision is expected in 2004.
	•	While commercial natural gas is yet to be discovered in this area, we have identified additional drill targets that are prospective for natural gas accumulation. The presence on our lands of a large structural feature (Robert’s Bank Gravity Anomaly) approximately 19 kms²in size has been supported by government gravity and onshore seismic data.
	•	The Geological Survey of Canada has assigned the Georgia Basin a reserve estimate of 6.5 trillion cubic feet of natural gas.


Other Non-Core Properties	•	Peavey/Morinville, Alexander, Simonette, Stanmore and Westlock in Alberta comprise 19,321 gross acres (14,491 net) with a weighted average WI of 75% and generated 8% of our production in Nine-Month Fiscal Transition 2002.
	•	We own a 50% working interest in 11,360 gross acres (5,680 net) of petroleum and natural gas leases at Quirk Creek. There are no producing wells on the property. We were inactive there during Nine-Month Fiscal Transition 2002 and expect to be inactive in 2003.

Reserves of Natural Gas, Natural Gas Liquids and Crude Oil

Our independent reserves estimates effective January 1, 2003 are prepared by Sproule Associates Limited of Calgary, Alberta (“Sproule”) and are shown in the following tables.

Reserves of Natural Gas, Natural Gas Liquids and Crude Oil
(Before royalties)

			Natural Gas
	Natural Gas		Liquids		Crude Oil	Equivalent
	(mmcf)		(mbbls)		(mbbls)	(mboe)

Proved producing	19,690		1,122		667	5,070
Proved non-producing	12,004		361		739	3,100

Total proved (P)	31,694		1,483		1,406	8,170
Probable additional (PA)	11,591		296		883	3,111

Total P+PA as of December 31, 2002	43,285		1,779		2,288	11,281
Total P+PA as of March 31, 2002	44,740		1,905		553	9,915

Increase (decrease)	(1,455	)	(126	)	1,735	1,366
Increase (decrease) %	(3.3)%		(6.6)%		313.7%	13.8%

Natural gas -during Nine-Month Fiscal Transition 2002, our estimated proved plus probable (P+PA) natural gas reserves decreased by a net of 1,455 mmcf or 3.3%, to 43,285 mmcf from Fiscal 2002. Factors contributing to this net decrease were production of 3,898 mmcf and a downward revision of 10,444 mmcf to previous reserve estimates made on our Peavey/Morinville and Halkirk properties. These factors were largely offset by new reserves acquired at St. Albert of 588 mmcf, and new extensions and discoveries at St. Albert and Cypress of 12,299 mmcf.

Natural gas liquids -during Nine-Month Fiscal Transition 2002, our natural gas liquids P+PA reserves decreased by a net of 126 mbbls or 6.6%, to 1,779 mbbls from Fiscal 2002. Most of our production of 192 mbbls originated from liquid-rich natural gas at St. Albert. Acquisitions, estimates, extensions and discoveries at St. Albert served to increase reserves by 66 mbbls.

Crude oil - during Nine-Month Fiscal Transition 2002, our estimated crude oil P+PA reserves increased by a net of 1,735 mbbls or 313.7% to 2,288 mbbls from Fiscal 2002. This net increase was due to new extensions, discoveries and revisions totaling 1,810 mbbls less production of 75 mbbls. All of our crude oil originates from the St. Albert field.

Reconciliation of Proved (P) + Probable Additional (PA) Reserves

			Natural Gas
	Natural Gas		Liquids		Crude Oil		Equivalent
	(mmcf)		(mbbls)		(mbbls)		(mboe)

Opening reserves as at March 31, 2002	44,740		1,905		553		9,915
Acquisitions	588		18		-		116
Revision of previous estimates	(10,444	)	18		1,180		(544	)
Production	(3,898	)	(192	)	(75	)	(916	)
Extensions and discoveries	12,299		30		630		2,710

Year-end reserves as at December 31, 2002	43,285		1,779		2,288		11,281

Our net present value (“NPV”) of P+PA reserves was determined according to the Canadian Provincial Securities Administrators’ National Policy No. 2-B, using a constant gas price of $5.50 per mcf and a constant oil price of $43.43 per barrel. These prices were our actual weighted average commodity prices received in December 2002, and along with associated operating costs, were assumed constant over the life of the reserves.

Our estimated 10% discounted net present value (npv) of P+PA reserves as at December 31, 2002 increased by $66.9 million or 87.4%, to $143.4 million over our npv as at March 31, 2002. This represented an increase in our npv per share of $3.31 or 88.5%, to $7.05 per share based on our number of shares outstanding as at the end of each period (December 31, 2002 and March 31, 2002 - 20.4 million, basic).

Discounted net present value
(Before taxes, after royalties)

($ 000’s)	0%	10%	15%

Proved producing	106,503	74,117	65,512
Proved non-producing	58,241	35,534	29,469

Total proved (P)	164,744	109,651	94,981
Probable additional (PA)	62,787	33,775	27,339

Total P+PA as at December 31, 2002	227,531	143,426	122,320
Total P+PA as at March 31, 2002	116,510	76,526	65,239

Increase (decrease)	111,021	66,900	57,081
Increase (decrease) %	95.3%	87.4%	87.5%

Reserve Life Indices

	Nine-Month Period Ended	Twelve-Month
	Dec 31, 2002	Period	Twelve-Month Period
	Annualized ¹	Ended Mar 31, 2002	Ended Mar 31, 2001

Proved (yrs)	6.7	7.5	8.4
Proved plus probable additional (yrs)	9.2	8.4	9.5

To be meaningful and comparable, our reserve life index for Nine-Month Fiscal Transition 2002 is annualized by multiplying the period’s production of 916 mboe by four-thirds to arrive at 1,222 mboe. This annualization method does not reflect actual results for a complete 12-month period. Actual results may vary from the information presented.

Our proved reserve life indices have, over the past three reporting periods, shown steadily improving exploitation of proved reserves. Proved plus probable additional reserve indices show we have opportunity to optimize reserve extraction.

On the next several pages, maps help to locate our various property locations that are detailed above.

Item 5. Operating and Financial Review and Prospects

Prior to this filing, our most recently filed annual report covered the twelve-month period ended March 31, 2002. Since then, we changed our fiscal year end to December 31. This Transition Report covers the nine-month transition period from April 1, 2002 to December 31, 2002. Where useful for comparison purposes, annualized numbers are presented by applying the nine-month transition numbers multiplied by four-thirds. However, this method does not reflect actual results for the three-month extrapolated period and such results may differ from the result achieved by this calculation. Also, for ease of reading, we may refer to the nine-month period ended December 31, 2002 as “Nine-Month Fiscal Transition 2002”; the 12-month period ended March 31, 2002 as “Fiscal 2002”; and the 12-month period ended March 31, 2001 as “Fiscal 2001”.

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

Certain statements in this Transition 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 worldwide website or otherwise, in the future, by or on behalf of us. 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 and the negotiation and closing of material contracts. 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.

We wish to caution readers not to place undue reliance on any forward-looking statement and to 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 assume no obligation to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

Operating Results

Summary

During Nine-Month Fiscal Transition 2002, we continued to strengthen our technical team with the addition of highly-experienced talent in engineering, geophysics and geology. We added new growth opportunities at Cypress/Chowade and Wimborne and we continued drilling and completion activities at St. Albert and Halkirk. Further, we added to our undeveloped land holdings and seismic database at Orion, Cypress/Chowade and Wimborne. These, we believe, are higher-risk, higher-reward properties that afford pure exploration opportunities.

Our primary strategy is to grow through the drill bit and consistent with that strategy, we have formed a team that is expert in exploration and development growth-oriented activities. During Nine-Month Fiscal Transition 2002, we stepped-up our daily average production by 107 boe/d or 3%, to 3,332 boe/d and increased our total corporate reserves by 1,366 mboe or 14%, to 11,281 mboe. However, at St. Albert, we did not meet our drilling schedule due to unexpected delays in receiving regulatory approvals for our drilling program. To carry out our near-term objectives and ensure our longer-term ability to fully utilize the St. Albert field, we have begun a public consultation process to provide information to the community and to expand liaison with local authorities and landowners.

We believe we are well positioned to achieve growth through exploration and development of our significant undeveloped land position and our solid inventory of drillable prospects.

Drilling Activity

	Nine-Month Fiscal
	Transition 2002		Fiscal 2002		Fiscal 2001

	Gross	Net	Gross	Net	Gross	Net
Natural gas	7	4.3	9	7.5	14	10.7
Crude oil	2	1.5	1	0.7	1	0.9
Dry	-	-	4	2.8	2	1.9

Total	9	5.8	14	11.0	17	12.5

Success rate		100%		75%		85

We operated or participated in nine drilled wells and one re-completed well over the nine months, resulting in seven natural gas wells and three oil wells for an overall success rate of 100%. Of the seven natural gas wells, five were drilled as exploratory outpost wells at Cypress/Chowade in northeast British Columbia and two were drilled as development wells at St. Albert and Halkirk, Alberta. Of the three oil wells, two were drilled and one was a re-completed previous natural gas well at St. Albert.

Management’s Discussion and Analysis of Operating and Financial Results

The following discussion and analysis should be read in conjunction with the financial statements and notes to the financial statements included in this Transition Report. The financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The impact of the significant differences between Canadian and United States generally accepted accounting principles on the financial statements is disclosed in Note 12 to the financial statements under Item 17 of this Transition Report.

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

Highlights	Nine-
	Month
	Fiscal
	Transition	%		Fiscal		%		Fiscal
($ 000’s)	2002	Chg		2002		Chg		2001

Earnings	1,978	156		(3,519	)	(136	)	9,714
Earnings per share	0.10	159		(0.17	)	(135	)	0.49
Cash flow from operations⁽¹⁾	10,723	(5	)	11,337		(38	)	18,168
Cash flow from operations per share⁽¹⁾	0.53	(4	)	0.55		(38	)	0.91
Natural gas, liquids and oil production (boe/d)⁽²⁾	3,332	3		3,225		22		2,644
Capital expenditures	12,578	(43	)	22,111		91		11,582
Established reserve additions (mboe)	1,366	84		741		247		(504	)
Debt⁽³⁾	16,818	27		13,281		-		-
Debt to cash flow (times)⁽⁴⁾	1.6:1			1.2:1				-
Debt to cash flow annualized⁽⁵⁾	1.2:1			1.2:1		-

⁽¹⁾

	Nine-
	Month
	Fiscal
	Transition		%		Fiscal	%
($ 000’s)	2002		Chg		2002	Chg		Fiscal 2001

Cash flow from operating activities (GAAP measure)	11,370		16		9,779	(49	)	19,264
Changes in non-cash working capital (GAAP measure)	(647	)	(142	)	1,559	242		(1,096	)

Cash flow from operations (non-GAAP measure)	10,723		(5	)	11,337	(38	)	18,168

⁽²⁾	Production and reserves include our working interest before royalties. We have presented our working interest before royalties as we measure our performance on this basis consistent with other Canadian oil and gas companies.
⁽³⁾	Debt is working capital, as we do not have any long-term debt.
⁽⁴⁾	Debt divided by cash flow from operations.
⁽⁵⁾	Debt divided by annualized cash flow from operations.

Cash Flow from Operations and Earnings

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Cash flow from operations decreased by a net $0.6 million or 5%,to $10.7 million mainly due to the following factors:

	•	A decrease due to the comparatively shorter reporting period;
	•	A decrease of $5.3 million due to a 22% decrease in total production;
	•	An increase of $3.0 million due to an 18% aggregate increase in weighted average commodity prices; and
	•	An increase of $1.7 million due mainly to a 16% decrease in royalties expense.

Earnings increased by a net $5.5 million or 156%, to $2.0 million mainly due to the following factors:

	•	A net decrease of $0.6 million from the same factors affecting our cash flow from operations explained above;
	•	An increase of $5.7 million due to a decrease in depletion expense;
	•	An increase of $3.3 million due to a decrease in exploration expenses; and
	•	A decrease of $2.9 million due to an increase in future income tax expense.

Fiscal 2002 vs Fiscal 2001
Cash flow from operations decreased by a net $6.8 million or 38%, to $11.3 million mainly due to the following factors:

	•	An increase of $5.2 million due to a 22% increase in total production;
	•	A decrease of $13.2 million due to a 38% aggregate decrease in weighted average commodity prices; and
	•	An increase of $1.2 million due mainly to a 32% decrease in royalties expense.

Earnings decreased by a net $13.2 million or 136%, to $(3.5) million mainly due to the following factors:

	•	A net decrease of $6.8 million due to the same factors affecting our cash flow from operations explained above;
	•	A decrease of $9.2 million due to an increase in depletion expense, $6.8 million of which related to a ceiling test write-down of Peavey/Morinville assets and the balance related to additional working interests acquired at St. Albert;
	•	A decrease of $2.7 million due to an increase in exploration expense;
	•	A decrease of $0.6 million due to a decrease in gains on the sale of land interests; and
	•	An increase of $6.1 million due to a reduction to future income tax expense.

The following information provides additional detail on the components affecting various increases and decreases itemized above in cash flow from operations and earnings.

Revenue

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Revenues decreased by $2.3 million or 9%, to $24.1 million. The following table shows price-volume variances.

Revenue Variances
($ 000’s)	Price	Volume		Total

Natural gas	2,152	(6,095	)	(3,943	)
Natural gas liquids	307	(737	)	(430	)
Crude oil	521	1,573		2,094

Total	2,980	(5,259	)	(2,279	)

On an annualized basis, revenues would have increased by $5.8 million or 22%, to $32.2 million.

Fiscal 2002 vs Fiscal 2001
Revenues decreased by $8.1 million or 23%, to $26.4 million. The following table shows price-volume variances:

Revenue Variances
($ 000’s)	Price		Volume	Total

Natural gas	(10,851	)	3,846	(7,005	)
Natural gas liquids	(2,197	)	704	(1,493	)
Crude oil	(111	)	548	437

Total	(13,159	)	5,098	(8,061	)

Daily Average Production Rates and Annual Production

	Nine-Month Fiscal	%			%
	Transition 2002	chg		Fiscal 2002	chg		Fiscal 2001

Natural gas (mcf/d)	14,174	(6	)	15,107	21		12,486
Natural gas liquids (bbl/d)	698	11		631	19		530
Crude oil (bbl/d)	271	257		76	130		33
Equivalent (boe/d)	3,332	3		3,225	22		2,644
Total production (mboe)	916	(22	)	1,177	22		965
Gas weighting (%)	71	(9	)	78	(1	)	79
Annualized production (mboe)	1,221	4		1,177	22		965

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Our total production decreased by 261 mboe or 22%, to 916 mboe mainly due to the comparatively shorter reporting period. On an annualized basis, however, total production would increase by 44 mboe or 4%, to 1,221 mboe.

Corporate Production

Daily average production rates

•

Our total daily average production rate increased by a net 107 boe/d or 3%, to 3,332 boe/d. Of this net increase, natural gas decreased by 155 boe/d or 6%, to 2,362 boe/d (14.2 mmcf), natural gas liquids increased by 67 boe/d or 11%, to 698 boe/d, while crude oil increased by 195 boe/d or 257%, to 271 boe/d.

2003 expected daily production exit rate

•

In 2003 we anticipate an increase in daily average production of approximately 1,900 boe/d or 57%, to 5,200 boe/d.

The following are discussion and variance analyses of our major fields and their individual impacts on our total daily average production rates:

St. Albert, Alberta

Daily average production rates

	•	Natural gas and natural liquids production rates decreased by 71 boe/d or 3%, to 2,574 boe/d (15.4 mmcf/d) due mainly to natural decline in reservoir pressures; and
	•	Crude oil output increased by 188 boe/d or 229%, to 261 boe/d due to the addition of three new oil wells at St. Albert, the largest of which commenced production for 61 days at a daily average rate of 498 boe/d net to us.

2003 expected daily production exit rates

	•	Natural gas and natural liquids production exit rates are expected to remain at current levels, as we plan to mitigate natural declines in reservoir pressures through third-party compression; and
	•	Crude oil rates are expected to increase by approximately 1,450 boe/d to a total exit rate of 1,725 boe/d through added drilling and wellbore re-entries. While discoveries may have greater daily production potential, our on-site battery capacity limits us at 1,725 boe/d.

Halkirk, Alberta

Daily average production rates

•

Production of natural gas and natural gas liquids decreased by 32 boe or 10%, to 288 boe/d on an operating day basis over Fiscal 2002, due to decreasing reservoir pressures.

2003 expected daily average production exit rates

•

We expect to offset natural decline rates by drilling and tying-in additional wells and adding third-party compression at this property.

Peavey/Morinville, Alberta

Daily average production rates

•

Natural gas rates decreased by 161 boe/d or 61%, to 104 boe/d (0.6 mmcf/d) due mainly to production declines.

2003 expected daily average production exit rates

•

In 2003, we anticipate a continued decline in production rate because we do not plan to spend further capital or add new production at this property.

Cypress/Chowade, NE British Columbia

Daily average production rates

•

We drilled and completed five natural gas wells that did not produce in Nine-Month Fiscal Transition 2002 because they were not yet tied-in.

2003 expected daily average production exit rates

•

We expect to add 450 boe/d (2.7 mmcf/d) by tying-in two natural gas wells. We believe it possible to tie-in the three remaining wells and add 850 boe/d (5.1 mmcf/d), however, tie-ins are not contemplated in our aggregate production exit rate, as they are not expected until late 2003.

Fiscal 2002 vs Fiscal 2001
Our total production increased by 212 mboe or 22%, to 1,177 mboe mainly due to the acquisition of additional working interests at St. Albert.

Weighted Average Commodity Prices

The following table shows our weighted average commodity prices for the periods presented.

	Nine-Month Fiscal	%		%
	Transition 2002	chg	Fiscal 2002	chg		Fiscal 2001

Natural gas ( $/mcf)	4.36	14	3.81	(39	)	6.22
Natural gas liquids ($/bbl)	20.90	8	19.30	(37	)	30.64
Crude oil ($/bbl)	41.40	21	34.33	(21	)	43.60

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Our weighted average prices of all commodities produced by us increased by percentage changes ranging from between 8% to 21%.

	•	Market prices during Nine-Month Fiscal Transition 2002 for natural gas were relatively strong until July 2002, at which time they plummeted. Later in the period, as cold weather in the eastern United States settled in, increased demand and supply concerns resulted in stronger regional prices.
	•	Prices for crude oil were strong during Nine-Month Fiscal Transition 2002 due to strengthening of the West Texas Intermediate benchmark price, reflecting geo-political uncertainties and tighter crude oil supplies.
	•	Our natural gas liquids are 45% natural-gas based and 55% crude-oil based, therefore, liquids prices follow the respective commodity price trends.

Fiscal 2002 vs Fiscal 2001
Our weighted average prices of all commodities produced by us decreased by percentage changes ranging from between 21% to 39%.

•

Prices for natural gas in Fiscal 2002 softened from those of Fiscal 2001, as North American inventories rose. Prices for crude oil in Fiscal 2002 softened from those of the Fiscal 2001, as sluggish demand after September 11, 2001 and increased inventory levels drove down prices.

Royalties, Mineral Taxes and Alberta Royalty Tax Credits (ARTC)

The following table shows our royalties, mineral taxes and Alberta royalty tax credits and unit royalties per boe for the periods presented.

	Nine-Month Fiscal		%				%
($ 000’s, unless otherwise stated)	Transition 2002		chg		Fiscal 2002		chg		Fiscal 2001

Crown	1,252		(5	)	1,317		(55	)	2,958
Freehold and overriding	3,327		(18	)	4,067		(37	)	6,106
Freehold mineral taxes⁽¹⁾	943		(16	)	1,116		41		794
ARTC	(178	)	12		(159	)	68		(499	)

Total	5,344		(16	)	6,341		(32	)	9,359
Per boe ($)	5.83		8		5.39		(44	)	9.70

⁽¹⁾	Based on current industry trend, we have reclassified mineral taxes from Production Costs to Royalties during the twelve months ended March 31, 2002. For comparison purposes, prior year amounts have been restated in the Statement of Operations and Deficit.

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Total royalties expense decreased by $1.0 million or 16%, to $5.3 million due mainly to the comparatively shorter reporting period. Unit royalties expense increased by $0.44 or 8%, to $5.83 per boe due primarily to royalty obligations associated with production of prior periods, higher commodity prices and a mineral tax reassessment related to Fiscal 2002.

Fiscal 2002 vs Fiscal 2001
Total royalties decreased by a net of $3.0 million or 32%, to $6.3 million and unit royalties decreased by $4.31 or 44%, to $5.39 per boe, due mainly to lower commodity prices that affect royalties and our purchase of an overriding royalty interest at St. Albert in Fiscal 2002. Partially offsetting these decreases was a non-recurring increase due to a payment in the Fiscal 2002 of certain mineral taxes associated with production of Fiscal 2001.

Production Costs

The following table shows our production and unit production costs per boe for the periods presented.

	Nine-Month Fiscal	%		Fiscal 2002	%		Fiscal 2001
($ 000’s, unless otherwise stated)	Transition 2002	chg			chg

Production costs⁽¹⁾- total	5,470	(6	)	5,846	(55	)	4,580
Per boe ($)	5.97	20		4.97	5		4.75

⁽¹⁾	Based on current industry trend, we have reclassified mineral taxes from Production Costs to Royalties during Fiscal 2002. For comparison purposes, prior year amounts have been restated in the Statement of Operations and Deficit.

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Production costs decreased by $0.4 million or 6%, to $5.5 million due mainly to the comparatively shorter reporting period. Unit production costs increased by $1.00 or 20%, to $5.97 per boe mainly due to the following:

	•	An increase of $0.33 per boe from higher electricity costs at St. Albert;
	•	An increase of $0.22 per boe from plant and battery maintenance costs at St. Albert not conducted in Fiscal 2002.
	•	An increase of $0.45 per boe was due to increases in field compression charges and well maintenance costs.

		In 2003, we expect unit production costs to change from current levels by:

	•	A decrease of $0.51 per boe due to the elimination of monthly sales and leaseback charges at St. Albert (see Note 5 to our Financial Statements);
	•	A savings of $0.22 per boe, as the gas plant and oil battery maintenance costs performed in Nine-Month Fiscal Transition 2002 will not be required; and

•

An increase in compression charges for natural gas produced from St. Albert. At the time of filing this Transition Report, we continue to negotiate compression charges, however, we expect them to be within industry-acceptable norms.

Fiscal 2002 vs Fiscal 2001
Production costs increased by $1.3 million or 55%, to $5.8 million and unit production costs increased by $0.22 or 5%, to $4.97 per boe, due mainly to the acquisition of additional working interests at St. Albert, resulting in greater volumes of higher-cost, liquid-rich natural gas being processed.

Amortization and Depletion Expenses (A&D)

The following table shows our amortization and depletion, and unit amortization and depletion expense per boe for the periods presented.

	Nine-Month Fiscal		%				%
($ 000’s, unless otherwise stated)	Transition 2002		chg		Fiscal 2002		chg	Fiscal 2001

A&D before the following:	5,924		11		5,336		72	3,097
- Ceiling test adjustment	445		(93	)	6,783		-	36
- Future removal and
site restoration provision	167		(41	)	284		54	185
- Amortization of
deferred Items	(109	)	53		(230	)	26	(311	)

Total A&D	6,427		(47	)	12,173		305	3,007
Per boe ($)	7.02		(32	)	10.34		231	3.12

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Our total A&D decreased by $5.7 million or 47%, to $6.4 million due mainly to the comparatively shorter reporting period. Unit A&D costs decreased by a net of $3.32 or 32%, to $7.02 per boe due to the following reasons:

	•	An increase of $0.34 per boe mostly due to added depletion in two new fields, Alexander and Halkirk that commenced production late in Fiscal 2001; and
	•	A decrease of $3.66 per boe mainly due to the Peavey/Morinville ceiling test adjustment taken in Fiscal 2002.

Fiscal 2002 vs Fiscal 2001
Total A&D increased by $9.2 million or 305%, to $12.2 million. Unit A&D costs increased by $7.22 or 231%, to $10.34 per boe due primarily to the following:

	•	An increase of $5.31 per boe mainly due to the Peavey/Morinville ceiling test adjustment taken in Fiscal 2002; and
	•	An increase of $1.76 per boe due to new production coming on at St. Albert and Halkirk at higher finding and development cost levels.

Exploration Expenses

The following table shows our exploration expenses and unit exploration expenses per boe for the periods presented.

	Nine-Month Fiscal	%			%
($ 000’s, unless otherwise stated)	Transition 2002	chg		Fiscal 2002	chg		Fiscal 2001

Drilling	325	(91	)	3,821	472		668
Seismic data activity	847	31		649	(41	)	1,102
Other	187	6		176	14		153

Total	1,359	(71	)	4,646	142		1,923
Per boe ($)	1.48	(63	)	3.95	98		1.99

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Exploration costs decreased by $3.3 million or 71%, to $1.4 million. Unit exploration expenses decreased by $2.47 or 63%, to $1.48 per boe due mainly to the following:

•

A decrease in costs associated with unsuccessful drilling attempts of $2.63 per boe, offset by an increase of $0.15 per boe in seismic expenses. All drilling attempts were successful in Nine-Month Fiscal Transition 2002. However, in Fiscal 2002 a total of ten wells were written off to dry hole expense, six of which were at Peavey/Morinville, one each at Quirk Creek, Alexander and Orion, and one reentry/workover at St. Albert.

Our 2003 budget of $2.8 million for exploration expenses is to acquire 3D and 2D seismic data.

Fiscal 2002 vs Fiscal 2001
Exploration costs increased by $2.7 million or 142%, to $4.6 million. Unit exploration expenses increased by $1.96 or 98%, to $3.95 per boe due mainly to the following:

•

An increase in dry hole costs of $2.27 per boe, offset by a decrease in seismic costs of $0.32 per boe. Dry hole expense increased significantly over Fiscal 2001 due to the ten dry holes discussed above.

Gain on Sale of Natural Gas and Oil Interests

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
There were no significant transactions to report in either of these two periods.

Fiscal 2002 vs Fiscal 2001
We sold a 50% working interest in a portion of our Orion leases in Fiscal 2001. The proceeds on the sale were $1.0 million for a gain of $0.6 million.

Interest Expense and Interest Income (Net Interest)

The following table shows our interest expense, interest income and net interest expense and unit net interest expense per boe for the periods presented.

	Nine-Month Fiscal		%				%
($ 000’s, unless otherwise stated)	Transition 2002		chg		Fiscal 2002		chg		Fiscal 2001

Interest expense	454		(8	)	494		106		240
Interest income	(2	)	(91	)	(22	)	(12	)	(25	)

Interest expense - net	452		(4	)	472		120		215
Per boe ($)	0.49		23		0.40		82		0.22

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
There was no material variance between periods in our net interest expense because our operating loan was used for nine months in each period at an average balance outstanding of approximately $12.5 million. The effective interest rate was 5.0% and 4.7% for Nine-Month Fiscal Transition 2002 and Fiscal 2002, respectively.

Fiscal 2002 vs Fiscal 2001
Our average loan-level usage was $12.7 million in Fiscal 2002 compared to $3.4 million in Fiscal 2001.

General and Administrative Expenses (G&A)

The following table shows our general and administrative, and unit general and administrative expenses per boe for the periods presented.

	Nine-Month Fiscal	%			%
($ 000’s, unless otherwise stated)	Transition 2002	chg		Fiscal 2002	chg	Fiscal 2001

General & administrative	1,926	(18	)	2,347	50	1,569
Per boe ($)	2.10	6		1.99	22	1.63

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
G&A decreased by $0.4 million or 18%, to $1.9 million due mainly to the comparatively shorter reporting period. Unit G&A costs increased by $0.11 or 6%, to $2.10 per boe due mainly to the following:

	•	A decrease of $0.05 per boe in overhead credits that we earn for operating properties. In the Nine-Month Fiscal Transition 2002, we operated fewer capital projects than in the Fiscal 2002;.
	•	Geophysical costs increased by $0.03 per boe due to increased costs for software and support; and
	•	Insurance premiums increased by $0.02 per boe and fees relating to regulatory filing obligations increased by $0.01 per boe.

Our G&A budget for 2003 is $2.4 million, an amount required to maintain continuing growth plans.

Fiscal 2002 vs Fiscal 2001
G&A increased by $0.8 million or 50%, to $2.3 million. Unit G&A costs increased by $0.36 or 22%, to $1.99 per boe due to salaries, interest, insurance and professional fees related to our acquisition of additional working interests at St. Albert.

Income Taxes

The following table shows our current and future income tax expenses for the periods presented.

	Nine-Month Fiscal	%			%
$(000’s)	Transition 2002	chg	Fiscal 2002		chg		Fiscal 2001

Income tax expense
- Current	207	257	58		(90	)	572
- Future	961	149	(1958	)	(147	)	4,163

Total	1,168	161	(1,900	)	(140	)	4,735

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.

Nine-Month Fiscal Transition 2002 vs Fiscal 2002
Total income tax expense increased to $1.2 million from a recovery of $1.9 million. This expense was consistent with our pre-tax earnings. Our effective tax rate was 37.1%, a rate that is in line with statutory tax rates.

Fiscal 2002 vs Fiscal 2001
Total income taxes in Fiscal 2002 reflect a recovery of $1.9 million versus an expense in Fiscal 2001 of $4.7 million. This recovery was consistent with our pre-tax loss.

Income Tax Pools Available for Deduction Against Future Taxable Income

The following table shows income tax pools available to us for the periods presented.

	Nine-Month Fiscal			Maximum Annual
$(000’s)	Transition 2002	Fiscal 2002	Fiscal 2001	Deduction

Cdn exploration expense	1,586	-	-	100%
Non-capital losses	-	-	-	100%
Share issue costs	-	-	-	100%
Cdn development expense	5,246	3,772	3,307	30%
Undepreciated capital costs	10,356	10,297	5,554	20% - 100%
Cdn oil/gas property expense	17,417	16,471	3,986	10%

Total	34,605	30,540	12,847

Commitments

As at December 31, 2002 we had an operating lease on our office premises covering 3,809 square feet.

We are committed to dismantling and restoring all sites upon which we have drilled or placed surface facilities. (See Note 13 to our Financial Statements.under Item 17 in this Transition Report).

Critical Accounting Policies

Our critical accounting policies are defined as those that are important both 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 under Item 17 in this Transition Report).

Reserves Estimates- On an annual basis, we engage independent petroleum consultants to conduct evaluations of our natural gas, natural gas liquids and crude oil 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, “BUSINESS RISK MANAGEMENT, Estimating of Reserves and Future Net Cash Flows Risk”.

Natural Gas and Crude Oil Interests- We follow the successful efforts method of accounting for our natural gas and crude oil activities, as described in Note 1 to our Financial Statements under Item 17 in this Transition Report. 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 and when it is determined that drilling has been unsuccessful in establishing commercial reserves, the costs of drilling are written off immediately and reported as exploration expense. Drilling costs for wells that have been successful in establishing commercial reserves are capitalized as natural gas and oil interests on our balance sheet.

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

Estimates of undiscounted future cash flows that we use for conducting ceiling tests are subject to significant judgment decisions based on assumptions of highly uncertain future factors such as, natural gas, natural gas liquids 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 ceiling test to be a critical accounting procedure.

In the period ended December 31, 2002, our property ceiling tests resulted in partial ceiling test adjustments to the book values of four properties: Alexander, Halkirk, Morinville/Peavey and Virgo. Total adjustments amounted to a $0.4 million reduction, Halkirk accounting for 74% and Alexander 21% of the total.

In the period ended March 31, 2002, ceiling test adjustments totaled $6.8 million, 99% of which related to the Peavey/Morinville property. The ceiling test adjustment recorded in the period ended March 31, 2001 was negligible.

Recently Issued Accounting Standard

Asset Retirement Obligations -A new Canadian standard “Asset Retirement Obligations” (ARO) substantially harmonizes Canadian GAAP with U.S. GAAP (see Note 12[e] to our Financial Statements in the Transition Report). The standard requires that a liability associated with the retirement of property, plant and equipment be recognized when incurred. The liability would be measured initially at fair value and the resulting costs capitalized. Capitalized costs would be amortized according to normal amortization practices. Subsequent to initial recognition, the ARO liability would be adjusted for the accretion of

discount and changes in the amount or timing of the underlying future cash flows. The standard is effective no later than January 1, 2004. We are evaluating the impact of the standard.

Inflation

We operate in Canada only, where inflation for our operational costs is at low levels, i.e. in the 2% to 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 in the past three fiscal periods.

Liquidity and Capital Resources

Liquidity

As at December 31, 2002, we had a working capital deficit of $16.8 million that included a balance owing to our corporate bank of $11.1 million under a revolving, demand credit facility with a borrowing maximum of $21.0 million (see Note 4 to our Financial Statements under Item 17 in this Transition Report). The $11.1 million balance resulted in a net debt years-to-repay ratio for Nine-Month Fiscal Transition 2002 of 1.6:1, a ratio that is determined by using our cash flow from operations for only nine months. On an annualized basis, our years-to-repay ratio is 1.2:1. Comparatively, our net debt years-to-repay ratio for Fiscals 2002 and 2001 were 1.2:1 and nil, respectively.

Principal balances outstanding bear interest at the federal prime rate established by the Bank of Canada plus % and are collateralized by a general assignment of book debts and a floating charge debenture of $35.0 million covering all our assets. A standby fee of % per annum is levied on the unused portion of the facility.

Our capital resources at December 31, 2002 consisted of cash flow from operations and available lines of bank credit.

Our 2003 capital investment and exploration expense budgets are $23.7 million and $2.8 million, respectively, totaling $26.5 million. We expect to fund this total mainly from cash flow provided by operations and our revolving, demand credit facility. Also during 2003, we expect 780,000 stock options to be exercised and provide us with net proceeds of $1.3 million.

Our working capital and debt levels are primarily dependent upon our operating cash flows, the amount of our capital investment and the timing of incurred field activities.

Financial Instruments

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

Substantially all of our accounts receivable at December 31, 2002 and March 31, 2002 resulted from the sale of natural gas, natural gas liquids and crude oil to other companies in the oil and gas industry. This concentration of customer type may impact our 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, we have not incurred credit losses against our receivables. At December 31, 2002, five customers represented 56% of our accounts receivable balance.

We have no agreements with management, investors, shareholders or anyone else respecting the raising of additional capital through stock issuances at this time.

Outlook for 2003

2003 Capital Investment Program
Our 2003 capital budget is $23.7 million. We plan to invest this capital as follows:

	•	$8.7 million or 37% in Alberta to maintain and grow production levels on existing core properties;
	•	$4.8 million or 20% in British Columbia to bring into production a new core property;
	•	$2.8 million or 12% in Alberta to explore for new reserves;
	•	$6.5 million or 27% in British Columbia to explore new frontier properties; and
	•	$0.9 million or 4% other.

Of the total budget amount, $10.8 million is for drilling, $6.1 million for new land acquisitions, $5.4 million for completions and tie-ins and $1.4 million for facilities.

This program is consistent with our strategy to grow reserves and production through the drill bit and is our largest-ever capital spending budget.

2003 Daily Production
We expect our daily production exit rate to reach 5,200 boe per day, a 57% increase over our daily average production levels for Nine-Month Fiscal Transition 2002 of 3,332 boe per day, a difference of approximately 1,900 boe per day. This difference is comprised of 1,450 boe per day of crude oil and 450 boe per day (2.7 mmcf/d) of natural gas.

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 2003 activity.

		Changes in			Effect on Cash Flow

		Volume	Price	Rate	($000’s)	$/share

Production	– natural gas (mcf/d)	1,000	-	-	1,430	0.068
	- natural gas liquids (bbls/d))	100	-	-	570	0.027
	- crude oil (bbls/d)	100	-	-	758	0.036
Price	- natural gas ($/mcf)	-	0.50	-	2,136	0.101
	- natural gas liquids ($/bbl)	-	1.00	-	232	0.011
	- crude oil ($/bbl)	-	1.00	-	319	0.015
Interest rate (%)		-	-	1	150	0.007

Contractual Obligations

The following table shows our contractual obligations for the periods indicated.

		Payments Due by Period
		Less than	1 - 3	3 – 5	More than
$(000’s)	Total	1 year	years	years	5 years

Operating lease obligations (office space)	79	73	6	-	-
Long-term debt, capital lease, purchase and
other long-term obligations	nil	nil	nil	nil	nil

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, 2002.

Name	Position Held	Age	Residence

Directors and Executive Officers:
Wayne J. Babcock	President & CEO, Director	59	Vancouver, B.C.
Donald K. Umbach	Vice President & COO, Director	49	Vancouver, B.C.
John A. Greig	Director	61	Vancouver, B.C.
Jonathan A. Rubenstein	Director	53	Vancouver, B.C.
David J. Jennings	Director	39	Vancouver, B.C.
John Lagadin	Director	65	Calgary, Alta.
William B. Thompson	Director	58	Kelowna, B.C.
Michael A. Bardell	CFO & Corporate Secretary	56	Vancouver, B.C.
David G. Grohs	Vice President, Production	37	Vancouver, B.C.
James R. Britton	Vice President, Exploration	68	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 20 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 principle of his own Petroleum Landman consulting firm. Mr. Umbach is a director of ours and is Vice President and Chief Operating Officer and has been such 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 director and chairman of Cumberland Resources Ltd. He is also director of Redcorp Ventures Ltd, First Step Ventures Ltd., 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 us since July 1990.

Mr. Rubenstein is a director of the following public companies: Redcorp Ventures Ltd., Cumberland Resources, Canico Resource Corp. and Commander 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, a past member of the Vancouver Stock Exchange Advisory Committee, and 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 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 and financier 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; and most recently investor and President of GeoScope Exploration Technologies, Inc., a company using proprietary, state-of-the-art seismic interpretation techniques to explore for oil & gas.

He is an independent 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 in the natural gas industry. He is currently an independent businessman.

Mr. Lagadin is a member of the Board of Directors of Cabre Exploration, Petro-Reef Resources and Direct Energy Marketing. Mr. Lagadin has been a director of ours since August, 2000.

William B.
Thompson
Director

Mr. Thompson holds a BSc 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 Associating 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.

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 14 years experience in the Canadian oil and gas industry, including positions with Shell Canada Limited, Numac Energy Inc., and ENCO Gas, Ltd. David Grohs is responsible for production operations, engineering and acquisitions.

James R.
Britton
Vice President,
Exploration

Mr. Britton, P.Eng., has a B.A.Sc. in Geological Engineering from the University of Toronto and is a member of the British Columbia Association of Petroleum Engineers and the Association of Professional Engineers, Geologists and Geophysicists of Alberta.

Mr. Britton is our Vice President, Exploration and has been associated with us since 1986.

None of our 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

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

We changed our financial year end from March 31 to December 31 effective December 31, 2002. For reference purposes, the most recently-completed financial reporting period covering the nine-months ended December 31, 2002 may be termed, “Nine-Month Fiscal Transition 2002”.

The following table sets forth all annual and long-term compensation for services in all capacities to us for Nine-Month Fiscal Transition 2002 in respect of each of the individuals comprised of the Chief Executive Officer and our other four most highly compensated executive officers whose individual total compensation for Nine-Month Fiscal Transition 2002 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 Nine-Month Fiscal Transition 2002 (collectively “the Named Executive Officers”). The information is presented in accordance with applicable Canadian regulations regarding reporting financial information on individual persons.

Named Executive Officers

Name/Position	Salary⁽¹⁾	Bonus	Other Annual Compensation⁽²⁾	Options Granted(#)⁽³⁾	Exercise Price	Expiry Date

Wayne J. Babcock
President & CEO	85,210	Nil	199,738	Nil	n/a	n/a
Donald K. Umbach
Vice President & COO	85,210	Nil	199,738	Nil	n/a	n/a
David G. Grohs,
Vice-Pres, Production	102,701	20,250	Nil	Nil	n/a	n/a
Michael A. Bardell,
CFO & Corporate Secretary	74,275	30,500	Nil	Nil	n/a	n/a
James R. Britton
Vice-Pres., Exploration	54,774	Nil	199,738	Nil	n/a	n/a

⁽¹	⁾	We changed our financial year end from March 31 to December 31 effective December 31, 2002. As a result, the transition year from the old financial year to the new financial year is Nine-Month Fiscal Transition 2002. “Salary” amounts shown in the table above cover the nine-months of Nine-Month Fiscal Transition 2002 rather than a twelve-month period.

⁽²	⁾	The other annual compensation paid is in respect of payments to each of three Named Executive Officers pursuant to management royalty agreements. We pay 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 (for two Named Executive Officers) and June 1, 1987 (for the third Named Executive Officer). See Note⁽¹⁾above for period covered by compensation.

⁽³	⁾	We have a formalized stock option plan for the discretionary granting of incentive stock options to the Named Executive Officers. No grants of stock options were made during Nine-Month Fiscal Transition 2002 to any of the Named Executive Officers.

During Nine-Month Fiscal Transition 2002, we paid to our senior officers total compensation (including as applicable, payments made pursuant to management royalty agreements, an aggregate sum of $929,183.

As of July 13, 1990, we had overriding management royalty agreements with Wayne J. Babcock and Donald K. Umbach and as of August 31, 1990, we had an overriding management royalty agreement with James R. Britton. Each of the overriding management royalty agreements requires us to pay 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 for Mr. Babcock and Mr. Umbach and since June 1, 1987 for Mr. Britton.

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 overriding royalty agreements and employment contracts described above, we had as of the end of the Nine-Month Fiscal Transition 2002 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.

The following table sets forth all compensation for services in all capacities to us for Nine-Month Fiscal Transition 2002 in respect of each of the non-employee directors.

Compensation of Non-Employee Directors

			Other Annual	Options	Exercise
Name/Position	Salary⁽¹⁾	Bonus	Compensation	Granted (#)⁽²⁾	Price	Expiry Date

John A. Greig				17,500	$1.65	29-Apr-2012
Director	Nil	Nil	Nil	15,000	$1.75	21-Aug-2012
Jonathan A. Rubenstein				17,500	$1.65	29-Apr-2012
Director	Nil	Nil	Nil	15,000	$1.75	21-Aug-2012
David J. Jennings⁽³⁾				17,500	$1.65	29-Apr-2012
Director	Nil	Nil	Nil	15,000	$1.75	21-Aug-2012
John Lagadin				5,000	$1.65	29-Apr-2012
Director	Nil	Nil	Nil	15,000	$1.75	21-Aug-2012
William B. Thompson⁽⁴⁾
Director	Nil	Nil	Nil	15,000	$2.95	16-Dec-2012

⁽¹⁾	During Nine-Month Fiscal Transition 2002 , 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, annual granting of incentive stock options to outside directors. 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. Mr. Jennings performs legal work on our behalf as a Barrister and Solicitor with the firm of Irwin, White & Jennings (1999). He was formerly a Partner in the firm of DuMoulin Black (1995-99). Mr. Jennings’ Nine-Month Fiscal Transition 2002 legal fees amounted to $26,625.

⁽⁴⁾	Mr. Thompson was appointed as a director through board nomination on December 17, 2002.

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 or officers, as a group as of May 5, 2003.

Stock Options Outstanding as of May 5, 2003
(Directors/Officers, as a group)

		Number of Shares of
Expiry Date	Exercise Price	Common Stock

January 23, 2005	$1.45	25,000
September 28, 2005	$2.10	300,000
April 3, 2006	$1.70	80,000
February 28, 2007	$1.75	210,000
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		1,068,750

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 May 5, 2003.

Stock Options Outstanding as of May 5, 2003
(Non-Directors/Non-Officers)

		Number of Shares of
Expiry Date	Exercise Price	Common Stock

July 14, 2003	1.72	18,000
January 23, 2005	1.45	20,000
July 30, 2005	1.75	30,000
September 28,2005	2.10	48,000
February 28, 2006	2.17	21,000
April 14, 2006	2.25	60,000
February 27, 2007	1.75	92,500
October 6, 2007	2.05	10,000
December 8, 2007	2.46	5,000
March 16, 2008	3.80	30,000

Total		334,500

Stock Options Granted to and Exercised by Named Executive Officers

During Nine-Month Fiscal Transition 2002 there were no options granted to any of the Named Executive Officers.

During Nine-Month Fiscal Transition 2002, there were no options exercised by executive officers, employee directors or non-employee directors.

The following table sets forth details of the number of stock options held as of May 5, 2003 by each of the Named Executive Officers. The table also sets forth the May 5, 2003 value of unexercised in-the-money options/SAR’s on an aggregated basis.

Stock Options Held by Named Executive Officers

		Dollar Value of Unexercised In-the-
	Number of Unexercised Options/SAR’s	Money Options/SAR’s Held At
	Held At May 5, 2003⁽¹⁾	May 5, 2003⁽²⁾
Name	Exercisable / Unexercisable	Exercisable / Unexercisable

Wayne J. Babcock	120,000/40,000	277,000/104,000
Donald K. Umbach	120,000/40,000	277,000/104,000
David G. Grohs	26,666/73,334	70,332/193,668
Michael A. Bardell	63,333/26,667	147,166/69,334
James R. Britton	60,000/20,000	138,500/52,000

⁽¹	⁾	No stock appreciation rights have been granted, therefore, the numbers relate solely to stock options.
⁽²	⁾	Value of unexercised in-the-money options calculated using the closing price of our shares of common stock on the Toronto Stock Exchange on May 5, 2002, less the exercise price of in-the-money stock options.

Board Practices

Term of Office

At our annual general meeting held on August 27, 1998, our shareholders approved amending our Articles 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 Nine-Month Fiscal Transition 2002, we had seven directors, one of which was board-appointed for the first time on December 17, 2002. The terms of all seven expire at the annual meetings of shareholders as follows:

	•	three in Fiscal 2003;
	•	two in Fiscal 2004; and
	•	two in Fiscal 2005.

Name	Term of Office Remaining	Held Office Since


Directors:
Wayne J. Babcock	Two years	1980
Donald K. Umbach	Two years	1986
John A. Greig	One year	1991
Jonathan A. Rubenstein	One year	1991
David J. Jennings	Three years	1999
John Lagadin	Three years	2000
William B. Thompson	Partial year	December 17, 2002

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 Nine-Month Fiscal Transition 2002.

List of Directors, Committees and Committee Members

	Full Board	Corporate		Audit
		Governance	Compensation	Reserves	Audit

Non-Employee Directors
John Greig	x	x	x		Chair
Jonathan Rubenstein⁽¹⁾	x	x	Chair		x
David Jennings⁽²⁾	x	Chair	x		x
John Lagadin⁽²⁾	x			x
Bill Thompson⁽¹⁾⁽²⁾	x				x

Employee Directors
Wayne Babcock	Chair
Don Umbach	x

⁽¹	⁾	Qualifies as a “financial expert” under US regulatory requirements.
⁽²	⁾	As of April 3, 2003, Mr. Thompson was appointed to the Audit Reserves Committee and replaced Mr. Jennings on the Audit Committee. Also, Mr. Lagadin was appointed Chair of the Reserves 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.

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 independence of the independent engineering firm; and
	•	review the annual estimated reserves as prepared by the independent engineers.

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. The Compensation Committee expects to accomplish this through defining the key components for executive officer compensation, being a base salary comparable to executive salaries in established peer group companies, and long-term incentives in the form of stock options. Short-term incentives in the form of a cash bonus could be paid for significant contributions to us. In combination, these elements are designed to recognize those activities of management that advance our short and long-term business objectives. The Compensation Committee meets as required, but not less than annually.

The Compensation Committee met three times during Nine-Month Fiscal Transition 2002. We have never provided compensation in the form of any plan providing compensation intended to serve as incentive for performance to occur over a period longer than one fiscal year and have not set aside or accrued for pensions. However, the shareholders previously approved royalty agreements with three Named Executive Officers whereby we pay 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.

During Nine-Month Fiscal Transition 2002, members of the Compensation Committee recommended, and the Board of Directors approved, the granting of 15,000 options to two of our newly hired employees. There were no option repricings during Nine-Month Fiscal Transition 2002. Also, during Nine-Month Fiscal Transition 2002, the

Compensation Committee made no recommendations to the Board to change the level of compensation or the form of compensation for directors, officers or employees.

In fiscal 1999 the Compensation Committee retained the services of William M. Mercer Inc. (“Mercer”) of Calgary, Alberta to conduct a thorough executive compensation review. As a result of the Mercer report, the

Compensation Committee found that the salary levels of our executives were “outside and below the ranges of salaries for executives in comparable positions in the peer group of oil and gas producing companies”. On June 30, 1999, the Committee resolved to increase by $40,000, the base salary levels of each of the President and Chief Executive Officer, and the Vice President and Chief Operating Officer. After giving effect to these adjustments, the salary of these executives were in the lowest quartile of the peer group of companies. Also on June 30, 1999, the Compensation Committee resolved to increase the salary levels of three other executive positions by percentages ranging from 43% to 47% over base salary. No subsequent increases, other than cost of living adjustments, have been made to the salary levels.

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

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.

Employees

As of December 31, 2002, we employed sixteen people full time in our Richmond, British Columbia office. The persons employed are the President & CEO, the Vice President & COO, the CFO & Corporate Secretary, the Vice President, Exploration, the Vice President, Operations and eleven persons occupied with technical support, company and joint venture accounting, financial reporting, office management and land administration.

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

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 May 5, 2003, 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.

Share Ownership of Directors and Officers

		Number of Shares	Percent of
Name	Position	of Common Stock⁽¹⁾	Class

Wayne J. Babcock	President & CEO, Director	839,893	4.0
Donald K. Umbach	Vice President & COO, Director	417,016	2.0
John A. Greig	Director	143,077	0.7
Jonathan A. Rubenstein	Director	52,363	0.2
David J. Jennings	Director	Nil	-
John Lagadin	Director	Nil	-
William B. Thompson	Director	Nil	-
Michael A. Bardell	CFO & Corporate Secretary	221,374	1.1
James R. Britton	Vice President, Exploration	186,677	0.9
David G. Grohs	Vice President, Operations	15,000	0.1

⁽¹⁾Exclusive of exercisable and unexercisable options set forth in the table entitled, Stock Options Held by Named Executive Officers.

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

Related Party Transactions

Please see the description of our Overriding Royalty Agreements in Item 10 – “Material Contracts and Agreements – Overriding Royalty Agreements”.

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 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

During the period of January 1, 2003 to the date of this Transition Report, no significant change has occurred.

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 in the United States through the National Association of Securities Dealers Automated Quotation System ("NASDAQ") SmallCap 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 May 5, 2002, we had 21,051,196 shares of common stock outstanding. At that date, we estimate 66 shareholders of record resident in Canada holding 10,352,352 shares of common stock and 821 shareholders of record resident in the United States holding 10,698,844 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:

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

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
Fiscal 1999	1.90	1.40	1.38	0.88

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 (Cdn $)		NASDAQ Small Cap (U.S. $)

Nine-Month Fiscal Transition 2002	High	Low	High	Low

Q1 ended June 30, 2002	2.00	1.60	1.25	1.01
Q2 ended September 30, 2002	2.25	1.60	1.39	1.05
Q3 ended December 31, 2002	4.45	1.90	3.05	1.18

Fiscal 2002

Q1 ended June 30, 2001	2.52	1.69	1.75	1.06
Q2 ended September 30, 2001	2.35	1.55	1.55	0.92
Q3 ended December 31, 2001	2.05	1.56	1.31	1.02
Q4 ended March 31, 2002	2.05	1.60	1.34	1.00

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

Apr/2003	4.70	3.91	3.25	2.33
Mar/2003	4.44	3.55	3.00	2.30
Feb/2003	3.89	3.40	2.59	2.20
Jan/2003	4.10	3.10	2.62	1.65
Dec/2002	4.45	2.35	3.05	1.40
Nov/2002	2.60	2.25	1.64	1.41

Item 10. Additional Information

Memorandum and Articles of Association

Our objects and purposes as set forth in our Memorandum and Articles

Our Memorandum and Articles (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 - Part 15.1 of our Articles provides: “A Director who is, in any way, directly or indirectly interested in an existing or proposed contract or transaction with the Company or who holds any office or possesses any property whereby, directly or indirectly, a duty or interest might be created to conflict with his duty or interest as a Director shall declare the nature and extent of his interest in such contract or transaction or of the conflict or potential conflict with his duty and interest as a Director, as the case may be, in accordance with the provisions of the British Columbia Company Act (the “Company Act”).” Part 15.2 states: “A Director shall not vote in respect of any such contract or transaction with the Company in which he is interested [subject to certain exclusions as set forth in this Part] and if he shall do so his vote shall not be counted, but he shall be counted in the quorum present at the meeting at which such vote is taken.”

Director’s power, in the absence of an independent quorum, to vote compensation to themselves or any members of their body -Part 12.2 of our Articles provides: “The remuneration of the Directors as such may from time to time be determined by the Directors or, if the Directors shall so decide, by the members. Such 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.”

Borrowing powers exercisable by the directors and how such borrowing powers can be varied -Part 8.1 of our Articles provides: “The Directors may from time to time on behalf of the Company . . . borrow money in such manner and amount, on such security, from such sources and upon such terms and conditions as they think fit, 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 mortgage . . . or give other security on the undertaking, or on the whole or any part of the property and assets, of the Company (both present and future).” Part 8.2 states: “Any bonds, debentures or other debt obligations of the Company may be issued at a discount, premium or otherwise, and 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 or election 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 -Part 12.3 of our Articles states that “a Director shall not be required to hold a share in the capital of the Company as qualification for his office but shall be qualified as required by the Company Act to become or 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 Company 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 or special 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 of
shareholders are convoked

Annual Meeting -Part 9.1 of our Articles states: “Subject to any extensions of time permitted pursuant to the Company Act, . . . an annual general meeting shall be held once in every calendar year at such time (not being more than thirteen months after the holding of the last preceding annual general meeting) and place as may be determined by the Directors.”

Special Meeting -Part 9.4 of our Articles states: “The Directors may, whenever they think fit, convene an extraordinary general meeting. An extraordinary general meeting, if requisitioned in accordance with the Company Act, shall be convened by the Directors or, if not convened by the Directors, may be convened by the requisitionists as provided in the Company Act.” Part 9.6 of our Articles provides: “A notice convening a general meeting specifying the place, the day, and the hour of the meeting, and, in case of special business, the general nature of that business, shall be given as such provided in the Company Act and in the manner hereinafter in these Articles mentioned, or in such other manner (if any) as may be prescribed by ordinary resolution, whether previous notice thereof has been given or not, to such persons as are entitled by law or under these Articles to receive such notice from the Company.”

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

The Investment Canada Act (the “ICA”), enacted on June 20, 1985, requires prior notification to the Government of Canada on the “acquisition of control” of Canadian businesses by non-Canadians, as defined in the ICA. Certain acquisitions of control, discussed below, are reviewed by the Government of Canada. The term “acquisition of control” is defined as any one or more non-Canadian persons acquiring all or substantially all of the assets used in the Canadian business, or the acquisition of the voting shares of a Canadian corporation carrying on the Canadian business or the acquisition of the voting interests of an entity controlling or carrying on the Canadian business. The acquisition of the majority of the outstanding shares is deemed to be an “acquisition of control” of a corporation. The acquisition of less than a majority, but one-third or more, of the voting shares of a corporation is presumed to be an “acquisition of control” of a corporation unless it can be established that the purchaser will not control the corporation.

Investments requiring notification and review are all direct acquisitions of Canadian businesses with assets of Cdn. $5,000,000 or more (subject to the comments below on investors), and all indirect acquisitions of Canadian businesses (subject to the comments below on WTO investors) with assets of more than Cdn. $50,000,000 or with assets of between Cdn. $5,000,000 and Cdn. $50,000,000 that represent more than 50% of the value of the total international transaction. In addition, specific acquisitions or new business in designated types of business activities related to Canada’s cultural heritage or national identity could be reviewed if the Government of Canada considers that it is in the public interest to do so.

The ICA was amended with the implementation of the Agreement establishing the World Trade Organization (“WTO”) to provide for special review thresholds for “WTO investors”, as defined in the ICA. “WTO investor” generally means:

	•	an individual, other than a Canadian, who is a national of a WTO member (such as, for example, the United States), or who has the right of permanent residence in relation to that WTO member;
	•	governments of WTO members; and
	•	entities that are not Canadian controlled, but that are WTO investor controlled, as determined by rules specified in the ICA.

The special review thresholds for WTO investors do not apply, and the general rules described above do apply, to the acquisition of control of certain types of businesses specified in the ICA, including a business that is a “cultural business”. If the WTO investor rules apply, an investment in our shares by or from a WTO investor will be reviewable only if it is an investment to acquire control of us and the value of our assets is equal to or greater than a specified amount (the “WTO Review Threshold”). The WTO Review Threshold is adjusted annually by a formula relating to increases in the nominal gross domestic product of Canada. The 2002 WTO Review Threshold was $218,000,000.

If any non-Canadian, whether or not a WTO investor, acquires control of us by the acquisition of shares, but the transaction is not reviewable as described above, the non-Canadian is required to notify the Canadian government and to provide certain basic information relating to the investment. A non-Canadian, whether or not a WTO investor, is also required to provide a notice to the government on the establishment of a new Canadian business. If our business is then a prescribed type of business activity related to Canada’s cultural heritage or national identity, and if the Canadian government considers it to be in the public interest to do so, then the Canadian government may give a notice in writing within 21 days requiring the investment to be reviewed.

For non-Canadians (other than WTO investors), an indirect acquisition of control, by the acquisition of voting interests of an entity that directly or indirectly controls us, is reviewable if the value of our assets is then Cdn. $50,000,000 or more. If the WTO investor rules apply, then this requirement does not apply to a WTO investor, or to a person acquiring the entity from a WTO investor. Special rules specified in the ICA apply if the value of our assets is more than 50% of the value of the entity so acquired. By these special rules, if the non-Canadian (whether or not a WTO investor) is acquiring control of an entity that directly or indirectly controls us, and the value of our assets and all other entities carrying on business in Canada, calculated in the manner provided in the ICA and the regulations under the ICA, is more than 50% of the value, calculated in the manner provided in the ICA and the regulations under the ICA, of the assets of all entities, the control of which is acquired, directly or indirectly, in the transaction of which the acquisition of control of us forms a part, then the thresholds for a direct acquisition of control as discussed above will apply, that is, a WTO Review Threshold of Cdn. $218,000,000 (in 2002) for a WTO investor or threshold of Cdn. $5,000,000 for a non-

Canadian other than a WTO investor. If the value exceeds that level, then the transaction must be reviewed in the same manner as a direct acquisition of control by the purchase of our shares.

If an investor is reviewable, an application for review in the form prescribed by the regulations is normally required to be filed with the Director appointed under the ICA (the “Director”) prior to the investment taking place and the investment may not be consummated until the review has been completed. There are, however, certain exceptions. Applications concerning indirect acquisitions may be filed up to 30 days after the investment is consummated and applications concerning reviewable investments in culture-sensitive sectors are required upon receipt of a notice for review. In addition, the Minister (a person designated as such under the ICA) may permit an investment to be consummated prior to completion of the review, if he is satisfied that delay would cause undue hardship to the acquiror or jeopardize the operations of the Canadian business that is being acquired. The Director will submit the application to the Minister, together with any other information or written undertakings given by the acquiror and any representation submitted to the Director by a province that is likely to be significantly affected by the investment.

The Minister will then determine whether the investment is likely to be of net benefit to Canada, taking into account the information provided and having regard to certain factors of assessment where they are relevant. Some of the factors to be considered are:

	•	the effect of the investment on the level and nature of economic activity in Canada, including the effect on employment, on resource processing, and on the utilization of parts, components and services produced in Canada;
	•	the effect of the investment on exports from Canada;
	•	the degree and significance of participation by Canadians in the Canadian business and in any industry in Canada of which it forms a part;
	•	the effect of the investment on productivity, industrial efficiency, technological development, product innovation and product variety in Canada;
	•	the effect of the investment on competition within any industry or industries in Canada;
	•	the compatibility of the investment with national industrial, economical and cultural policies;
	•	the compatibility of the investment with national industrial, economic and cultural policies taking into consideration industrial, economic and cultural objectives enunciated by the government or legislature of any province likely to be significantly affected by the investment; and
	•	the contribution of the investment to Canada’s ability to compete in world markets.

To ensure prompt review, the ICA sets certain time limits for the Director and the Minister. Within 45 days after a completed application has been received, the Minister must notify the acquiror that he is satisfied that the investment is likely to be of net benefit to Canada, or that he is unable to complete his review, in which case he shall have 30 additional days to complete his review (unless the acquiror agrees to a longer period), or he is not satisfied that the investment is likely to be of net benefit to Canada.

Where the Minister has advised the acquiror that he is not satisfied that the investment is likely to be of net benefit to Canada, the acquiror has the right to make representations and submit undertakings within 30 days of the date of the notice (or any other further period that is agreed upon between the acquiror and the Minister). On the expiration of the 30-day period (or the agreed extension), the Minister must quickly notify the acquiror that he is now satisfied that the investment is likely to be of net benefit to Canada or that he is not satisfied that the investment is likely to be of net benefit to Canada. In the latter case, the acquiror may not proceed with the investment or, if the investment has already been consummated, must divest itself of control of the Canadian business.

The ICA provides civil remedies for non-compliance with any provision. There are also criminal penalties for breach of confidentiality or providing false information.

Except as provided in the ICA, there are no limitations under the laws of Canada, the Province of British Columbia or in any of our constituent documents on the right of non-Canadians to hold or vote our common shares.

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

There are no such limitations in our Memorandum or Articles, but 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 Memorandum or Articles governing the ownership threshold above which
shareholder ownership must be disclosed

There are no such provisions in our Memorandum or Articles.

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

The British Columbia Securities Act 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. The British Columbia Securities Act 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 the British Columbia Securities Act. 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 percent 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

All contracts/agreements we entered into during Nine-Month Fiscal Transition 2002 are considered to be immaterial and in the ordinary course of our business.

During Fiscals 2002 and 2001, we entered into the following ten agreements. Any other contracts/agreements that we have entered into during the same two reporting periods are considered to be immaterial and in the ordinary course of our business.

Transportation and Processing Agreement between ATCO Midstream Ltd. and us dated November 1, 2000 for the transportation and processing of natural gas produced by us from our Peavey/Morinville properties. The agreement was effective November 1, 2000 and is a one-year, renewable agreement.

Purchase and Sale Agreement dated June 26, 2001 between Fletcher Challenge Oil & Gas Inc. as “Vendor”, and Trioco Resources Inc., Energy North Inc. and us collectively as “Purchaser”. The agreement provided for the joint purchase by the Purchaser from the Vendor of certain petroleum and natural gas rights, tangibles and miscellaneous interests called the “Assets” in the St. Albert area of Alberta. The effective date was April 1, 2001 and the closing date was June 29, 2001. The purchase price paid was $34 million, of which our share (net of interim adjustments) was $15.5 million.

Contribution, Mutual Interest and Exclusion Agreement dated June 29, 2001 among Trioco Resources Inc., Energy North Inc. and us, whereby we agreed to purchase the assets at St. Albert pursuant to the Purchase and Sale Agreement (see June 26, 2001 agreement above). The agreement sets out the respective participating interests and liabilities of the parties pursuant to the Purchase and Sale Agreement.

Employment Agreements with Us

Wayne Babcock, President and Chief Executive Officer, dated July 11, 2000.

Donald K. Umbach, Vice President and Chief Operating Officer, dated July 11, 2000.

James Britton, Vice President, Exploration, dated July 11, 2000.

Michael Bardell, Chief Financial Officer, dated July 11, 2000.

David Grohs, Manager Engineering, dated March 5, 2001.

Jonathan White, Senior Geologist, dated March 12, 2001.

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 employee not to voluntarily leave the our employ during actions taken by third parties to acquire control of us. If an employee 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 employee 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 employee 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.

GasEDI Base Contract for Short-Term Sale and Purchase of Natural Gas dated October 15, 2001 for the short-term sale and purchase of natural gas between Nexen Marketing (“Nexen”) and us. Under the contract, Nexen agreed to hold and manage on our behalf all transportation agreements related to the contract, and to purchase all of our natural gas produced monthly from the St. Albert, Alexander, Peavey/Morinville, Halkirk and Stanmore fields. The monthly purchase price (“the Price”) payable to us is the calculated arithmetic average of the regional daily spot gas price index. Also under the contract, a portion of the gas produced monthly is re-purchased by us at the Price for re-sale to Progas Limited pursuant to a Gas Purchase Contract dated July 11, 1997 between Progas Limited and us.

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.

Except as provided in the Investment Canada Act ("the 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 foreigners to hold and/or vote the Common Stock.

The Act requires a non-Canadian making an investment to acquire control of a Canadian business, the gross assets of which exceed certain defined threshold levels, to file an application for review with Investment Canada, a federal agency created by the Act.

As a result of the Canada-U.S. Free Trade Agreement, the Act was amended in January 1989 to provide distinct threshold levels for Americans who acquire control of a Canadian business.

A Canadian business is defined in the Act as a business carried on in Canada that has a place of business in Canada, an individual or individuals in Canada who are employed or self-employed in connection with the business, and assets in Canada used in carrying on the business.

An American, as defined in the Act, includes: an individual who is an American national or a lawful permanent resident of the United States; a government or government agency of the United States; an American-controlled entity, corporation or limited partnership; and an American corporation, limited partnership or trust of which two-thirds of its Board of Directors, general partners or trustees, as the case may be, are Canadians or Americans.

The following investments by a non-Canadian are subject to review by Investment Canada:

	•	all direct acquisitions of control of Canadian businesses with assets of $5 million or more;
	•	all indirect acquisitions of control of Canadian business with assets of $50 million or more if such assets
	•	the degree and significance of participation by Canadians in the Canadian business and in any industry in Canada of which it forms a part;
	•	represent less than 50% of the value of the assets of the entities, the control of which is being acquired; and
	•	all indirect acquisitions of control of Canadian businesses with assets of $5 million or more if such assets represent more than 50% of the value of the assets of the entities, the control of which is being acquired.

Review by Investment Canada is required when investments by Americans exceed $150 million for direct acquisitions of control. For the purpose of the Act, direct acquisition of control means purchase of the voting interest of a corporation, partnership, joint venture or trust carrying on a Canadian business, or any purchase of all or substantially all of the assets used in carrying on a Canadian business.

If 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 the following investment: (i) an investment to establish a new Canadian business; and (ii) an investment to acquire control of a Canadian business which is not subject to review under the Act, must notify Investment Canada, within prescribed time limits, of such investment.

Impact of the North American Free Trade Agreement

The investment provisions of the North American Free Trade Agreement ("NAFTA") are fundamentally based on the basic structure, which was established under the Free Trade Agreement ("FTA") between Canada and the United States.

Basically, the same rules that currently apply to American investors in regard to the Investment Canada Act ("ICA"), will also be applicable to Mexican investors under NAFTA. However, under NAFTA, the annual increment in the minimum dollar threshold for direct acquisitions will be increased from where it is under the FTA by an amount equal to the increase in the gross domestic product during that year over the immediately prior year, as opposed to comparing current levels to the gross domestic product price index in 1992 (as under the FTA).

Canada, Mexico and the United States have agreed, under Article 1102 of NAFTA, to accord "national treatment" to investors from each other's country in relation to the establishment, acquisition, expansion, management, conduct, operation and sale or other disposition of investments. Under this principle, each party is to accord the investors of another party treatment no less favorable than it accords, in like circumstances, to its own investors with respect to such investments. The same principle extends to the investments of investors of another party within the territory of the host country.

Article 1103 of NAFTA obligates each party to accord to investors of each other party treatment no less favorable than it accords in like circumstances to investors of another party or of any non-party with respect to the establishment, acquisition, expansion, management, conduct, operation and sale or other disposition of investments. The same principle extends to the investments of investors of another party.

The effect of this provision is to ensure that any more favorable investment rules accorded to investors of third countries are similarly extended to investors of each of the other NAFTA parties.

In common with the approach taken under the FTA, NAFTA contains provisions in Article 1106 prohibiting the imposition of significant trade-distorting performance requirements by a NAFTA country in connection with any investments in its territory. The prohibited performance requirements include those relating to export levels, domestic content, local sourcing, product mandates, trade-balancing, technology transfers and product mandating.

In this regard, it should be noted that the restrictions relating to performance requirements, which tie the volume or value of exports from the host country or its foreign exchange earnings, as well as provisions relating to technology transfer and product mandating, represent additions in NAFTA over and above what was contained in the FTA. In the past, under the ICA and the Foreign Investment Review Act, Canada has often required undertakings from foreign investors in regard to product mandates. Canada has also occasionally insisted on foreign investors committing to give preference to local Canadian sources for goods and services. Article 1106 prohibits the enforcement of any commitment or undertaking to such effect, as well as the imposition of such commitments or undertakings. Therefore, while the basic structure of the ICA has been preserved under NAFTA, Canada will no longer be able to enforce any undertakings or commitments of the type described in Article 1106.

Except with the above noted minor exceptions, NAFTA has had little if any effect on the provision of the ICA.

Taxation

The following paragraphs set forth certain United States and Canadian federal income tax considerations in connection with the 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 ("United States Taxpayers") 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 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

United States citizens, residents or corporations owning shares of common stock must generally treat the gross amount of dividends paid by us without reduction for the amount of Canadian withholding tax, as dividend income for United States federal income tax purposes to the extent of our current and accumulated earnings and profits. Such dividends will generally not be eligible for the "dividends received" deduction allowed to United States corporations under Section 243 of the Code. 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. In computing the limitation on foreign tax credit, dividends paid by us might, depending on the circumstances, be treated in substantial part as income from sources within the United States, pursuant to Section 904(g) of the Code. Also, dividends paid by us will generally be "passive income" subject to a separate limitation on foreign tax credits.

The tax law contains provisions relating to so-called "passive foreign investment companies" ("PFIC's") that might have applied to us. If the PFIC provisions applied, certain tax and interest would apply to certain distributions by us and upon a disposition of shares of common stock by U.S. persons.

The sale of a share of our common stock generally result in the recognition of gain or loss to the holder in an amount equal to the difference between the amount realized and the holder's adjusted basis in such share. Provided the holder is not a dealer in the share sold, and the common share would be a capital asset to the holder, 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 and whether or not the PFIC provisions apply to us. The maximum federal tax rate on net long-term capital gains recognized by non-corporate taxpayers is 20%. The maximum federal tax rate on net capital gains recognized by corporations is 35%.

Capital losses are deductible to the extent of capital gains. Noncorporate taxpayers may deduct excess losses, whether short-term or long-term, to the extent of $3,000 a year ($1,500 in the case of a married individual filing separately). Noncorporate taxpayers may carry forward unused capital losses indefinitely. Unused capital losses of a corporate taxpayer may be carried back three years and carried forward five years.

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, Canada has amended the Income Tax Act of Canada so as to allow Canadian taxpayers making investments in oil and gas companies to 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 and up to $1.0 million of annual "development" 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 Nine-Month Fiscal Transition 2002, Fiscal 2002 and Fiscal 2001 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 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 2002 consist of cash and cash equivalents, accounts receivable, bank indebtedness, operating loan and accounts 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).

To summarize, 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 declines in the weight-averaged prices of our revenue-generating commodities (see also “Sensitivity Analysis” under Item 5 in this Transition Report).

	Weight-Averaged Prices
Nine-Month Fiscal Transition 2002	Achieved		After Consideration of Adversity %

	Final	Entire
	Quarter	Period	10%	20%	30%

Natural gas ( $/mcf)	$5.50	$4.36	$3.92	$3.49	$3.05
Natural gas liquids ($/bbl)	$24.69	$20.90	$18.81	$16.72	$14.63
Crude oil ($/bbl)	$41.57	$41.40	$37.26	$33.12	$28.98

Impact on Gross Revenues After Consideration of Pricing Adversity

The following table demonstrates the effects of weight-averaged pricing adversity as applied to our Nine Month Fiscal Transition 2002 gross revenues. Our cash flow from operations and earnings before taxes would experience the same effects.

Nine-Month Fiscal Transition 2002	Weight-Averaged Prices
($ 000’s)	Achieved		After Consideration of Adversity %

	Final	Entire
Commodity Type	Quarter	Period	10%	20%	30%

Natural gas	7,017	17,058	15,352	13,646	11,941
Natural gas liquids	1,608	4,012	3,611	3,210	2,808
Crude oil	1,885	3,052	2,747	2,442	2,136

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. All of our accounts receivable are with customers or joint venture partners in the energy industry and are subject to normal industry credit risk. For example, approximately 58% of our December 31, 2002 balance of accounts receivable is due from fivecustomers, subject to normal credit risk. Further, while our largest producing properties during Fiscal Transition 2002 were self-operated, five out of eleven 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 3/8% per annum. To

minimize our exposure to rate variability, we occasionally invest a portion of our undrawn borrowing capacity in Banker’s Acceptances (BA’s). We are charged a standby fee of 1/8% 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 “Sensitivity Analysis” under Item 5 in this Transition Report).

At December 31, 2002, we had floating debt outstanding of $11.1 million (March 31, 2002 - $14.8 million; March 31, 2001 – nil).

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 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.

Item 15. Controls and Procedures

Within the 90 days prior to the date of this Transition Report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Office and Principal Accounting Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based upon that evaluation, the Company's Chief Executive Officer and Principal Accounting Officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in the Company's periodic SEC filings. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to the date the Company carried out its evaluation.

Our CEO and CFO do not expect that our disclosure controls or our internal controls will prevent all error and all fraud. 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.	[Reserved]

	Not Applicable.

Item 16(A).	Audit Committee Financial Expert

	Not Applicable.

Item 16(B).	Code of Ethics

	Not Applicable.

Item 16(C).	Principal Accountant Fees and Services

	Not Applicable.

Part III.

Item 17. Financial Statements

Auditors’ Report	F-1

Balance Sheets as of December 31, 2002 and March 31, 2002	F-2

Statements of Operations and Deficit for Nine-Month Fiscal Transition 2002 and
the years ended March 31, 2002 and March 31, 2001	F-3

Statements of Cash Flows for Nine-Month Fiscal Transition 2002 and
the years ended March 31, 2002 and March 31, 2001	F-4

Notes to Financial Statements	F-5

Financial Statements

Dynamic Oil & Gas, Inc.
December 31, 2002 and March 31, 2002

AUDITORS’ REPORT

To the Shareholders of
Dynamic Oil & Gas, Inc.

We have audited the balance sheets ofDynamic Oil & Gas, Inc.as of December 31, 2002 and March 31, 2002 and the statements of operations and deficit and cash flows for the nine months ended December 31, 2002 and for the years ended March 31, 2002 and March 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2002 and March 31, 2002 and the results of its operations and its cash flows for the nine months ended December 31, 2002 and for the years ended March 31, 2002 and March 31, 2001 in accordance with Canadian generally accepted accounting principles. As required by the Company Act of British Columbia, we report that, in our opinion, these principles have been applied, except for the change in the method of accounting for stock-based compensation as explained in note 2, on a basis consistent with that of the preceding year.

Vancouver, Canada,	/s/ ERNST & YOUNG LLP
March 20, 2003.	Chartered Accountants

F-1

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

BALANCE SHEETS
(in Canadian dollars)

	December 31		March 31
	2002		2002
	$		$


ASSETS[note 4]
Current
Accounts receivable[note 10]	6,426,761		5,979,532
Prepaid expenses	351,771		365,227
Income taxes receivable	131,772		—

Total current assets	6,910,304		6,344,759

Future income tax asset[note 7]	—		279,000
Natural gas and oil interests[note 3]	36,568,076		30,365,636
Capital assets[note 3]	168,366		162,499

	43,646,746		37,151,894


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current
Bank indebtedness	1,519,923		842,812
Operating loan[note 4]	11,075,000		14,750,000
Accounts payable and accrued liabilities	11,133,844		3,611,314
Income taxes payable	—		421,360

Total current liabilities	23,728,767		19,625,486

Deferred gain on sale[note 5]	—		109,327
Provision for future removal and site restoration	990,982		824,098
Future income tax liability[note 7]	682,300		—

Total liabilities	25,402,049		20,558,911

Share capital[note 6]	20,720,629		20,914,522
Deficit	(2,475,932	)	(4,321,539	)

Total shareholders’ equity	18,244,697		16,592,983

	43,646,746		37,151,894

Commitments[notes 13 and 14]

See accompanying notes and schedules

On behalf of the Board:

Director: /s/ Wayne J. Babcock

Director: /s/ Donald K. Umbach

F-2

Dynamic Oil & Gas, Inc.

STATEMENTS OF OPERATIONS AND DEFICIT
(in Canadian dollars)

	Nine Months		Years Ended
	Ended		March 31
	December 31
	2002		2002		2001
	$		$		$


REVENUE
Natural gas, liquids and oil sales	24,122,754		26,401,872		34,462,676
Royalties[note 11]	(5,521,583	)	(6,500,447	)	(9,857,954	)
Production costs	(5,470,467	)	(5,845,958	)	(4,579,845	)

	13,130,704		14,055,467		20,024,877
Alberta royalty tax credit	178,098		159,274		498,773

	13,308,802		14,214,741		20,523,650


EXPENSES
General and administrative[schedule 1]	1,926,162		2,347,212		1,569,175
Interest expense on operating loan	454,251		494,685		240,420
Interest income	(1,732	)	(22,066	)	(25,601	)

	2,378,681		2,819,831		1,783,994


Earnings from operations before
the following:	10,930,121		11,394,910		18,739,656
Amortization and depletion[schedule 2]	6,426,785		12,172,943		3,006,964
Exploration expenses[schedule 3]	1,359,512		4,646,018		1,923,194
Gain on sale of natural gas and oil interests	(2,139	)	(4,566	)	(639,532	)

Earnings (loss) before taxes	3,145,963		(5,419,485	)	14,449,030

Income tax expense (recovery)[note 7]
- Current	207,000		57,600		572,000
- Future	961,300		(1,958,000	)	4,163,000

Net earnings (loss)	1,977,663		(3,519,085	)	9,714,030

Deficit, beginning of year	(4,321,539	)	(695,279	)	(10,379,392	)
Premium on purchase and cancellation of
common shares[note 6[d]]	(132,056	)	(107,175	)	(29,917	)

Deficit, end of year	(2,475,932	)	(4,321,539	)	(695,279	)


Earnings per share[note 8]
basic	0.10		(0.17	)	0.49
diluted	0.10		(0.17	)	0.48

See accompanying notes and schedules

F-3

Dynamic Oil & Gas, Inc.

STATEMENTS OF CASH FLOWS
(in Canadian dollars)

	Nine Months		Years Ended
	Ended		March 31
	December 31
	2002		2002		2001
	$		$		$


OPERATING ACTIVITIES
Net earnings (loss)	1,977,663		(3,519,085	)	9,714,030
Add (deduct) items not involving cash:
Amortization and depletion	6,426,785		12,172,943		3,006,964
Future income tax expense	961,300		(1,958,000	)	4,163,000
Exploration expenses	1,359,512		4,646,018		1,923,194
Gain on sale of natural gas and oil interests	(2,139	)	(4,566	)	(639,532	)

Funds flow from operations	10,723,121		11,337,310		18,167,656
Changes in non-cash working capital affecting
operating activities[note 9[a]]	646,829		(1,558,807	)	1,096,162

Cash provided by operating activities	11,369,950		9,778,503		19,263,818


FINANCING ACTIVITIES
Bank indebtedness	677,111		842,812		—
Operating loan	(3,675,000	)	14,750,000		(6,000,000	)
Shares issued for cash	—		455,420		200,000
Share repurchases	(325,948	)	(289,793	)	(89,689	)

Cash (used in) provided by financing activities	(3,323,837	)	15,758,439		(5,889,689	)


INVESTING ACTIVITIES
Purchase of capital assets	(84,420	)	(116,180	)	(78,749	)
Natural gas and oil interests	(12,493,116	)	(21,994,897	)	(11,502,902	)
Exploration expenses	(1,359,512	)	(4,646,018	)	(1,923,194	)
Proceeds on sale of natural gas and oil interests	2,139		4,566		1,072,395
Changes in non-cash working capital affecting
investing activities[note 9[b]]	5,888,796		(2,277,861	)	1,109,888

Cash used in investing activities	(8,046,113	)	(29,030,390	)	(11,322,562	)


(Decrease) increase in cash and cash equivalents	—		(3,493,448	)	2,051,567
Cash and cash equivalents, beginning of year	—		3,493,448		1,441,881

Cash and cash equivalents, end of year	—		—		3,493,448


Supplemental disclosures of cash flow information
Cash paid during the year for:
Interest	459,237		589,549		259,230
Income taxes	760,132		1,167,720		26,856

See accompanying notes and schedules

F-4

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

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 United States generally accepted accounting principles, except as explained in Note 12.

Change in fiscal year end

The Company changed its fiscal year end from March 31 to December 31, effective December 31, 2002. The following is a summary of selected financial information for the comparative twelve and nine-month periods ended December 31, 2002 and 2001.

Results of Operations

	Twelve Months Ended				Nine Months Ended

	December 31		December 31		December 31		December 31
	2002		2001		2002		2001

	(unaudited)		(unaudited)		(audited)		(unaudited)

Revenue	30,730,477		31,658,397		24,122,754		19,794,149
Net earnings (loss)	287,145		2,248,205		1,977,663		(1,828,567	)
Net earnings (loss) per share
basic	0.01		0.11		0.10		(0.09	)
diluted	0.01		0.11		0.10		(0.08	)
Cash flows
- provided by operating activities	15,128,790		14,949,163		11,369,950		6,019,663
- (used in) provided by financing
activities	(4,331,528	)	12,972,031		(3,323,837	)	16,766,130
- used in investing activities	(10,814,155	)	(29,877,314	)	(8,046,113	)	(26,262,348	)

F-5

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

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

Stock-based compensation

Effective April 1, 2002, the Company adopted the new standard (“CICA 3870”) recommended by The Canadian Institute of Chartered Accountants, Stock-Based Compensation and Other Stock-Based Payments. The new standard requires stock-based payments to non-employees, direct awards of stock and awards that call for settlement in cash to be accounted for using the fair value method. Under the fair value method, compensation expense is measured at the grant date and recognized over the service period using an option-pricing model.

While the Company accounts for stock-based payments to non-employees using the fair value method, it has elected to continue to use the intrinsic value method of accounting for stock options granted to employees and directors under its stock option plan. The Company has disclosed the required pro forma effect on earnings and earnings per share as if the fair value method of accounting as prescribed in CICA 3870 had been applied [see Note 6[c]].

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. All other costs of exploring and developing for proved reserves become capitalized natural gas and oil interests.

The cost of proved producing interests including related plant and equipment are depleted on a unit-of-production basis, based on proved producing natural gas and oil reserves.

Natural gas and oil interests are recorded at cost less accumulated provisions for depreciation, depletion and amortization. Natural gas and oil interests are assessed periodically for impairment whenever events or conditions indicate that their net carrying amount may not be recoverable from estimated future cash flows.

F-6

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

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

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.

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 the proceeds that arise 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.

Future removal and site restoration

Costs for the future removal and site restoration of natural gas and oil interests are based on estimates of liabilities and year of abandonment. The estimates of the liabilities are based on engineering estimates, which consider past experience, current regulations, technology and industry standards. Costs are amortized to earnings on a straight-line basis to the year of abandonment.

Capital assets

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

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

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.

F-7

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

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

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.

Foreign currency translation

The Company follows the temporal method of accounting for the translation of foreign currency amounts into Canadian dollars. Under this method, 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 income. 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 the provision for future removal and site restoration are based on estimates. Assessments for impairments in asset carrying costs are based on estimates of proved producing reserves, production rates, natural gas and oil prices, future costs and other relevant assumptions. By their nature these estimates are subject to measurement uncertainty and the effect on the financial statements of changes in such estimates in future years could be significant.

Revenue recognition

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

Deferred gain on sale and lease back

The deferred gain has been amortized to income over the lease back term [see Note 5].

F-8

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

3. NATURAL GAS AND OIL INTERESTS, AND CAPITAL ASSETS

		Accumulated
		Amortization and	Net Book
	Cost	Depletion	Value
	$	$	$


December 31, 2002
Natural gas and oil interests	61,657,575	25,089,499	36,568,076
Furniture, fixtures and computer equipment	538,153	369,787	168,366


March 31, 2002
Natural gas and oil interests	49,453,746	19,088,110	30,365,636
Furniture, fixtures and computer equipment	453,733	291,234	162,499

At December 31, 2002, costs of $8,796,000 [March 31, 2002 - $2,542,000] related to non-producing assets have been excluded from the calculation of amortization and depletion.

In the nine-month period ended December 31, 2002, the Company recorded asset write-downs of $445,467 [year ended March 31, 2002 - $6,783,248; year ended March 31, 2001 - $35,712] 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

Through the National Bank of Canada, the Company has available a revolving, demand credit facility of $21,000,000. Principal balances outstanding bear interest at prime plus 3/8% (bank prime rate at December 31, 2002 - 4.5%; March 31, 2002 - 3.8%) and are collateralized by a general assignment of book debts and a floating charge debenture of $35,000,000 covering all the assets of the Company. The effective average interest paid during the nine-month period ended December 31, 2002 was 5.0% [March 31, 2002 - 4.7%]. A standby fee of 0.125% per annum is levied on the unused portion of the facility.

F-9

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

5. ST. ALBERT SALE AND LEASEBACK

On December 18, 1997, the Company agreed to sell and lease back, for an initial term of five years, its St. Albert gas processing facilities to Enercap Corporation of Calgary, Alberta (“Enercap”). The impact on the Company of the sale was a reduction of natural gas and oil interests of $3,427,846, the elimination of a debenture payable in 1998 to Enercap of $4,832,352 and a gain on sale of $1,404,506. This gain on sale was deferred and amortized to income over the leaseback term up to December 31, 2002.

Pursuant to the sale and lease back agreement, the Company had the option to repurchase the St. Albert gas processing facilities from Enercap at the end of the five-year term. The Company exercised its option on December 31, 2002 for an option price of $780,000.

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:

	Number of
	Shares		$


Balance, March 31, 2001	20,145,930		20,641,720
Stock options exercised	495,100		455,420
Share repurchases and cancellations[note 6[d]]	(178,800	)	(182,618	)

Balance, March 31, 2002	20,462,230		20,914,522
Share repurchases and cancellations[note 6[d]]	(189,700	)	(193,893	)

Balance, December 31, 2002	20,272,530		20,720,629

F-10

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

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 inside directors, officers, employees and consultants 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. During the nine months ended December 31, 2002, all options issued were to either inside directors, officers or employees. In addition, under the plan, options granted to the Company’s outside directors have a maximum term of ten years and vest upon date of grant. 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, 2002, March 31, 2002, and March 31, 2001 is presented below:

	December 31		March 31			March 31
	2002		2002			2001

	Number	Weighted	Number		Weighted	Number		Weighted
	of	average	of		average	of		average
	shares	option price	shares		option price	shares		option price
	#	$	#		$	#		$


Outstanding at beginning of period	1,930,250	1.83	1,855,350		1.29	1,599,100		1.29
Granted	147,500	1.88	570,000		1.87	535,250		2.00
Exercised	—	—	(495,100	)	0.92	(279,000	)	0.72

Outstanding at period end	2,077,750	1.83	1,930,250		1.83	1,855,350		1.29

Options exercisable at period end	1,641,250	1.84	1,458,750		1.84	1,855,350		1.29


Exercise prices for the options outstanding as of December 31, 2002 ranged from 1.45 to 2.95 per share. These options have a weighted average remaining contractual life of 2.90 years.

F-11

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

6. SHARE CAPITAL (cont’d.)

[c]	Pro Forma Net Income - Fair-Value Based Method of Accounting for Stock Options

	The following shows pro forma net income and earnings per common share had the Company applied the fair value based method of accounting for all stock options outstanding.

		December 31
		2002
		$


	Net Earnings:
	- as reported	1,977,663
	- pro forma	1,771,987
	Basic earnings per common share:
	- as reported	0.10
	- pro forma	0.09
	Diluted earnings per common share:
	- as reported	0.10
	- pro forma	0.09


	The Black-Scholes options valuation model was used to estimate the fair value of non-employee options, which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. As the Company’s employee and director stock options have characteristics different from those of non-employee options, and 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 its employee and director 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:

		December 31
		2002
		$


	Dividend yield	0%
	Expected volatility	47%
	Risk-free interest rate	5%
	Expected lives	3 years


	The weighted average fair value per share of stock options granted during the nine month period ended December 31, 2002 is $0.91.

F-12

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

6. SHARE CAPITAL (cont’d.)

[d]	Issuer Bids

	Pursuant to the following normal course issuer bids, the Company was authorized to repurchase and cancel common shares on the open market through the facilities of the Toronto Stock Exchange and NASDAQ:

Normal course issuer bid date of		Share repurchases/
Commencement	Termination	cancellations authorized


1-May-02	31-Mar-03	1,000,000
9-Apr-01	31-Mar-02	1,000,000
1-Oct-99	30-Sep-00	1,000,000


Under these normal course issuer bids, the Company purchased and recorded the following:

	December 31				March 31				March 31
	2002				2002				2001

	#		$		#		$		#		$


Bid termination date: 31-Mar-03	(189,700	)	(325,948	)
Bid termination date: 31-Mar-02	—		—		(178,800	)	(289,793	)	—		—
Bid termination date: 30-Sep-00	—		—		—		—		(58,100	)	(89,689	)

	(189,700	)	(325,948	)	(178,800	)	(289,793	)	(58,100	)	(89,689	)

Average purchase price	$1.72				$1.62				$1.54
Recorded as an increase of deficit			132,056				107,175				29,917

Recorded as a reduction of share capital			(193,892	)			(182,618	)			(59,772	)

F-13

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

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		March 31
	2002		2002
	$		$


Long term future tax assets (liabilities):
CCA in excess of book depreciation	(1,015,300	)	(46,000	)
Finance charges	1,000		2,000
Deferred gain recognized for tax purposes	—		46,000
Provision for future removal and site restoration costs	332,000		277,000

Net future tax (liabilities) assets	(682,300	)	279,000

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

	December 31			March 31			March 31
	2002			2002			2001
	$		%	$		%	$		%


Tax at combined federal
and provincial rates	1,333,000		42.37	(2,371,000	)	43.75	6,483,000		44.87
Tax effect of non-deductible
crown royalties	898,400			1,068,000			1,329,000
Tax effect of income not
taxable	(70,500	)		(64,900	)		(224,000	)
Tax effect of resource allowance	(1,017,600	)		(1,290,300	)		(2,295,000	)
Large Corporation Tax in excess of
surtax	25,000			49,000			19,000
Effect of changes in tax rates	—			708,800			(577,000	)

	1,168,300			(1,900,400	)		4,735,000

F-14

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

8. EARNINGS PER SHARE

Basic net earnings (loss) per share was calculated on the basis of the weighted average number of shares outstanding for the nine-month period ended December 31, 2002 of 20,357,153 [March 31, 2002 - 20,365,031; March 31, 2001 - 19,937,585]. The weighted average number of shares outstanding for the diluted calculation in the nine-month period ended December 31, 2002 was 20,554,231 [March 31, 2002 - 20,466,543; March 31, 2001 - 20,444,979].

	December 31	March 31		March 31
	2002	2002		2001
	$	$		$


Numerator
Net earnings (loss) for the period	1,977,663	(3,519,085	)	9,714,030


Denominator
Weighted average number of common
shares outstanding	20,357,153	20,365,031		19,937,585
Effect of dilutive stock options	197,078	101,512		507,934

	20,554,231	20,466,543		20,444,979


Basic earnings (loss) per share	0.10	(0.17	)	0.49
Diluted earnings (loss) per share	0.10	(0.17	)	0.48

9. CHANGES IN NON-CASH WORKING CAPITAL BALANCES

[a]	Changes affecting operating activities comprise:

	December 31		March 31		March 31
	2002		2002		2001
	$		$		$


Accounts receivable	(968,683	)	(581,264	)	(2,463,146	)
Prepaid expenses	13,456		(124,761	)	(122,782	)
Accounts payable and accrued liabilities	2,155,188		(728,998	)	3,136,946
Income taxes payable	(553,132	)	(123,784	)	545,144

	646,829		(1,558,807	)	1,096,162

F-15

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

9. CHANGES IN NON-CASH WORKING CAPITAL BALANCES (cont’d.)

[b]	Changes affecting investing activities comprise:

	December31	March 31		March 31
	2002	2002		2001
	$	$		$


Accounts receivable	521,453	(953,434	)	217,404
Accounts payable	5,367,343	(1,324,427	)	892,484

	5,888,796	(2,277,861	)	1,109,888

10. FINANCIAL INSTRUMENTS

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

Substantially all of the Company’s accounts receivable at December 31, 2002, and March 31, 2002 result from the sale of natural gas, natural gas liquids and oil to 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, 2002 five customers represent 56% of the accounts receivable balance.

11. OVERRIDING ROYALTY

Three of the Company’s officers receive compensation pursuant to royalty agreements that have previously been approved by shareholders. The Company pays an overriding royalty interest of 1% of the Company’s 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 the Company since June 1, 1986 for two of the three officers and June 1, 1987 for the third officer. In the nine-month period ending December 31, 2002, the overriding royalty expense included in royalties is $681,493 [years ended March 31, 2002 - $745,994; March 31, 2001 - $934,338].

F-16

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

12. RECONCILIATION OF 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 earnings (loss) under U.S. GAAP would be:

	For the Nine Months		For the Year		For the Year
	Ended December 31		Ended March 31		Ended March 31
	2002		2002		2001
	$		$		$


Net earnings (loss) under Canadian GAAP	1,977,663		(3,519,085	)	9,714,030
Options issued for services [a]	(4,933	)	—		(20,100	)
Ceiling test adjustment to natural gas
properties [b]	(332,000	)	(216,100	)	—
Income taxes [c]	141,400		669,100		(577,000	)

Net earnings (loss) and comprehensive
earnings (loss) under U.S. GAAP	1,782,130		(3,066,085	)	9,116,930

Common shares - weighted average	20,357,153		20,365,031		19,937,585
Net earnings (loss) per common share under
U.S. GAAP
- basic	0.09		(0.15	)	0.46
- diluted	0.09		(0.15	)	0.45

After adjusting for certain differences, selected consolidated balance sheet items under U.S. GAAP would be:

	December 31				March 31
	2002				2002

	Canadian		U.S.		Canadian		U.S.
	Basis		Basis		Basis		Basis
	$		$		$		$


Future income tax asset [c]	—		—		279,000		371,100
Future income tax liability [c]	682,300		540,900		—		—
Natural gas and oil interests [b]	36,568,076		36,236,076		30,365,636		30,149,536
Share capital [a, d]	20,720,629		21,693,722		20,914,522		21,882,682
Deficit [a, b, c, d]	(2,015,480	)	(1,640,052	)	(4,321,539	)	(5,421,657	)

F-17

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

12. RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

[a]	Stock-based compensation

	Prior to the adoption of CICA 3870, no compensation expense was recognized under Canadian GAAP when stock options were issued to directors, employees or consultants. This resulted in a U.S. GAAP difference for the years ended March 31, 2002 and 2001 as the Company is required to account for stock-based compensation arrangements using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”) for employees and directors and the fair value method under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”) for consultants. Under APB 25, compensation expense for employees and directors is based on the difference between the fair value of the Company’s stock and the exercise price if any, on the date of the grant. Under SFAS 123, the Company accounts for stock options issued to consultants at fair value. While the Company follows APB 25 for employees and directors, it does comply with the disclosure provisions of SFAS 123. The Company has adopted the disclosure-only provisions of SFAS 123, “Accounting for Stock-Based Compensation” for stock based awards to employees and directors, consistent with current disclosure requirements under CICA 3870. Had compensation cost for the Company’s stock option plan been determined based on the fair value at the grant date for awards in the years ended March 31, 2002 and 2001 consistent with the provisions of SFAS No. 1223, the Company’s net earnings (loss) would have been decreased to the pro forma amounts indicated below:

	March 31		March 31
	2002		2001
	$		$


Net Earnings:
- as reported	(3,519,085	)	9,714,030
- pro forma	(3,356,108	)	9,313,819
Basic earnings per common share:
- as reported	(0.17	)	0.49
- pro forma	(0.16	)	0.47
Diluted earnings per common share:
- as reported	(0.17	)	0.48
- pro forma	(0.16	)	0.46

F-18

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

12. RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

	For the nine months ended December 31, 2002, the net earnings (loss) that would be disclosed to SFAS No. 123 is consistent with the amounts shown in note 6[c]. The weighted average assumptions used in the Black-Scholes valuation (refer to note 6[c] for discussion of the model) for the years ended March 31, 2002 and 2001 were as follows:

		March 31	March 31
		2002	2001
		$	$


	Dividend yield	0%	0%
	Expected volatility	57%	48%
	Risk-free interest rate	5%	6%
	Expected lives	3 years	3 years


[b]	Under the successful efforts method of accounting, according to Canadian GAAP, the net carrying cost of oil and gas properties in producing cost centres is limited to an estimated recoverable amount, which is the aggregate of future net operating revenues from proved producing reserves net of certain costs (the “Canadian ceiling test”). Under U.S. GAAP, costs accumulated in each cost centre are limited to an amount equal to the present value, using an annual cash flow discount rate of 10%, of the estimated future net operating revenues from proved producing reserves (the “U.S. ceiling test”).

[c]	Effective April 1, 1999, the Company adopted the new Canadian GAAP recommendations with respect to income taxes which requires application of the liability method of tax allocation, similar to the requirements under US GAAP. However, there remains a difference between Canadian and US GAAP, as Canadian GAAP requires that deferred income tax balances be adjusted to reflect substantively enacted rates rather than the current legislated tax rates under US GAAP.

[d]	Share issue costs are charged directly to retained earnings under Canadian GAAP and are charged directly to share capital under US GAAP. The total share issue costs charged to share capital was $570,961.

F-19

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

12. RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)

[e]	Recent Developments in US Accounting Standards

	In June 2001, the Financial Accounting Standards Board issued Statement No. 143, “Accounting for Asset Retirement Obligations” (FAS 143), which is effective for all fiscal years beginning after June 15, 2002. The Statement requires legal obligations associated with the retirement of long-lived assets to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of the liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. The liability accretes until the Company expects to settle the retirement obligation. The Company will adopt FAS 143 on January 1, 2003, however due to the extensive number of documents that must be reviewed and estimates that must be made to assess the effects of the Statement, the expected impact of the adoption of FAS 143 on the Company’s financial position or results of operations has not yet been determined.

13. COMMITMENTS

[a]	Operating lease

	The Company has entered into an operating lease in respect of its office premises. Minimum payments under this lease commitment, including estimated operating costs over the next two years are $72,329 and $6,027 for the fiscal years ending December 31, 2003 and 2004, respectively.

[b]	Future removal and site restoration costs

	The Company is responsible for the future removal and site restoration related to its natural gas and oil properties at the end of their useful lives. The Company currently estimates the total amount of this future liability to be approximately $2,110,750, of which $166,883 has been accrued in the current year with $1,085,113 remaining to be accrued in the future. Actual costs may differ from those estimated due to changes in legislation and estimated costs.

F-20

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
(in Canadian dollars)

December 31, 2002

14. ECONOMIC DEPENDENCY

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 re-negotiation.

F-21

Dynamic Oil & Gas, Inc.

Schedule 1
GENERAL AND ADMINISTRATIVE
(in Canadian dollars)

	Nine Months		Year Ended
	Ended		March 31
	December 31
	2002		2002		2001
	$		$		$


Advertising and promotion	180,249		250,792		218,880
Insurance	121,427		122,583		43,034
Interest	32,967		98,087		18,469
Office and printing	387,029		432,947		231,490
Professional fees	474,120		530,203		402,925
Provincial capital taxes	17,836		83,062		37,000
Regulatory and other fees	81,523		72,472		70,219
Rent	66,410		89,581		84,646
Salaries and benefits⁽¹⁾	783,706		1,086,958		633,601
Telephone	16,076		16,423		13,354
Travel	39,689		23,054		20,361
Cost recoveries	(274,870	)	(458,950	)	(204,804	)

	1,926,162		2,347,212		1,569,175

⁽¹⁾The Company also paid overriding royalties to three officers as described in Note 11.

Schedule 2
AMORTIZATION AND DEPLETION
(in Canadian dollars)


	Nine Months		Year Ended
	Ended		March 31
	December 31
	2002		2002		2001
	$		$		$


Amortization and depletion	6,369,230		12,118,849		3,132,663
Future removal and site restoration provision	166,883		284,368		184,925
Amortization of deferred financing costs	—		—		1,412
Amortization of deferred gain on sale	(109,328	)	(230,274	)	(312,036	)

	6,426,785		12,172,943		3,006,964

F-22

Dynamic Oil & Gas, Inc.

Schedule 3
EXPLORATION EXPENSES
(in Canadian dollars)


	Nine Months	Year Ended
	Ended	March 31
	December 31
	2002	2002	2001
	$	$	$


Drilling	325,477	3,821,374	667,684
Seismic data activity	846,984	649,216	1,101,969
Non-producing lease rentals	138,051	64,605	51,856
Property investigations	49,000	110,823	101,685

	1,359,512	4,646,018	1,923,194

F-23

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

We hereby certify that we meet all of the requirements for filing on Form 20-F and that we have duly caused and authorized the undersigned to sign this Transition Report on our behalf.

Date: May 14, 2003

Dynamic Oil & Gas, Inc.

By: /s/ Michael A. Bardell

Michael A. Bardell

Chief Financial Officer & Corporate Secretary

Certification

I, Wayne J. Babcock, certify that:

1.	I have reviewed this Transition Report on Form 20-F of Dynamic Oil & Gas, Inc.;

2.	Based on my knowledge, this Transition Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Transition Report;

3.	Based on my knowledge, the financial statements, and other financial information included in this Transition Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Transition Report;

4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

	a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, is made known to us by others within that entity, particularly during the period in which this Transition Report is being prepared;

	b)	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Transition Report (the "Evaluation Date"); and c) presented in this Transition Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

	a)	all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.	The registrant's other certifying officers and I have indicated in this Transition Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 16, 2003

/s/ Wayne J. Babcock

Wayne J. Babcock,
President and Chief Executive Officer

Certification

I, Michael A. Bardell, certify that:

1.	I have reviewed this Transition Report on Form 20-F of Dynamic Oil & Gas, Inc.;

2.	Based on my knowledge, this Transition Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Transition Report;

3.	Based on my knowledge, the financial statements, and other financial information included in this Transition Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Transition Report;

4.	The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

	a)	designed such disclosure controls and procedures to ensure that material information relating to the registrant, is made known to us by others within that entity, particularly during the period in which this Transition Report is being prepared;

	b)	evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Transition Report (the "Evaluation Date"); and c) presented in this Transition Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.	The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

	a)	all significant deficiencies in the design or operation of internal controls that could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

	b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.	The registrant's other certifying officers and I have indicated in this Transition Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 16, 2003

/s/ Michael A. Bardell

Michael A. Bardell, Chief Financial Officer
(Principal Financial and Accounting Officer)

INDEX TO EXHIBITS

		Sequentially
Exhibit Numbers	EXHIBITS	Numbered Page

1(a) and 2(a)(i)	Certificate of Incorporation and Articles/By-laws. (1)
1(b) and 2(a)(ii)	Certificate of Increase of Authorized Capital of the Company and Name Change.(3)
1(c) and 2(a)(iii)	Amendment to Articles of Incorporation re Staggered Board (6)	76
1(d) and 2(a)(iv)	Corporate Governance Committee Guidelines
2(a)(v)	Shareholder Rights Plan Agreement.(3)
4(i)	Joint Bidding Agreement by and between Imperial Oil Limited St. Albert Property Package, dated February 5, 1997. (1)
(ii)	Agreement of Purchase and Sale by and between Imperial Oil Resources and Fletcher Challenge Energy Canada, Inc., dated March 13, 1997. (1)
(iii)	Agreement for Purchase and Sale by and between Dynamic Oil Limited and Oiltec Resources Ltd., dated June 6, 1997. (1)
(iv)	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)
(v)	Gas Purchase Contract by and between Dynamic Oil Limited and Progas Limited, dated November 1, 1997. (1)
(vi)	Joint Operating Agreement (Shallow Rights) by and between Fletcher Challenge Energy Canada Inc. and Dynamic Oil Limited, dated May 30, 1997.(2)
(vii)	Joint Operating Agreement (Deep Rights) by and between Fletcher Challenge Energy Canada Inc. and Dynamic Oil Limited, dated May 30, 1997.(2)
(viii)	Joint Acquisition Agreement St. Albert Area by and between Fletcher Challenge Energy Canada Inc. and Dynamic Oil Limited, dated May 30, 1997.(2)
(ix)	Sale Agreement by and between Enercap Corporation and Dynamic Oil Limited, dated November 28, 1997.(2)
(x)	Gas Processing Agreement by and between Enercap Corporation and Dynamic Oil Limited, dated December 17, 1997.(2)
(xi)	Management Services Agreement by and between Enercap Corporation and Dynamic Oil Limited, dated December 17, 1997.(2)
(xii)	Demand Debenture and Negative Pledge by Dynamic Oil Limited in favor of Enercap Corporation, dated December 17, 1997.(2)
(xiii)	Purchaser’s Lenders Undertaking by and among Dynamic Oil Limited, Montreal Trust Company of Canada and Enercap Corporation, dated December 17, 1997.(2)
(xiv)	Sweet Gas Processing and Transportation Agreement between ATCO Gas Services Ltd. and Dynamic Oil & Gas Inc., dated December 16, 1998. (3)
(xv)	Natural Gas Sales Agreement between Producers Marketing Ltd. and Dynamic Oil & Gas, Inc., dated November 1, 1999 (re: Dynamic’s interests at Peavey/Morinville in Alberta). (4)
(xvi)	Transportation and Processing Agreement between ATCO Midstream Ltd. and Dynamic Oil & Gas, Inc. dated November 1, 2000 (re: Dynamic’s interests at Peavey/Morinville in Alberta). (5)
(xvii)	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.) (5)
(xviii)	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. (5)

(xix)	Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas, Inc. and Wayne Babcock. (5)
(xx)	Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas, Inc. and Donald K. Umbach. (5)
(xxi)	Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas, Inc. and James Britton. (5)
(xxii)	Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas, Inc. and Michael Bardell. (5)
((xxiii)	Employment Agreement, dated March 5, 2001 between Dynamic Oil & Gas, Inc. and David Grohs. (5)
(xxiv)	Employment Agreement, dated March 12, 2001 between Dynamic Oil & Gas, Inc. and Jonathan White. (5)
(xxv)	Overriding Royalty Agreement dated July 13, 1990 between Dynamic Oil Limited and Wayne J. Babcock. (5)
(xxvi)	Overriding Royalty Agreement dated July 13, 1990 between Dynamic Oil Limited and Donzoil Ltd. (5)
(xxvii)	Overriding Royalty Agreement dated August 31, 1990 between Dynamic Oil Limited and James R. Britton. (6)
6	Statement re: Earnings Per Share Calculation. (5)
12.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (7)	76
12.2	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (7)	77

Unless otherwise noted, each exhibit to this Transition 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 August 18, 1998.
(3	)	Form 20-F Annual Report filed on September 9, 1999.
(4	)	Form 20-F Annual Report filed on August 16, 2000.
(5	)	Form 20-F Annual Report filed on August 15, 2001.
(6	)	Form 20-F Annual Report filed on August 19, 2002.
(7	)	Filed herewith.

Exhibit 1(c) and 2(a)(iii)

I CERTIFY THIS IS A COPY OF A
DOCUMENT FILED ON

FORM 19
(Section 348)

/s/ John S. Powell

PROVINCE OF BRITISH COLUMBIA

12 JOHN S. POWELL

REGISTRAR OF COMPANIES	Certificate of
PROVINCE OF BRITISH COLUMBIA	Incorporation No.188,587

COMPANY ACT

SPECIAL RESOLUTION

The following special resolution was passed by the undermentioned Company on the date stated:

NAME OF COMPANY:

DYNAMIC OIL LIMITED

DATE RESOLUTIONS PASSED: August 27,1998

Resolution:

"BE IT RESOLVED as Special Resolutions that Article 13.1 of the Articles of the Company be deleted in its entirety and replaced with the following:

13.1 At each annual general meeting of the Company all the directors whose term of office expire at such annual general meeting shall retire and the members entitled to vote thereat shall elect to the Board of Directors the number of directors for the time being fixed pursuant to these Articles. A retiring director shall be eligible for re-election. The directors shall be classified, with respect to the duration of the term for which they severally hold office, into three classes (denominated Class I, Class II and Class III) as nearly equal in number as reasonably possible. The term of office of the initial Class I directors shall expire at the annual general meeting of the Company in 2001, the term of office of the initial Class II directors shall expire at the annual general meeting of the Company in 2000, and the term of office of the Initial Class ffl directors shall expire at the annual general meeting of me Company in 1999. At each annual general meeting of the Company, beginning in 1999, the successors of the Class of directors whose term expires at the annual general meeting of the Company shall be elected to hold office for a term expiring at the annual general meeting of the Company held in the third year following the year of their election. When a director is elected, such director's Class shall be identified. A director elected to fill a vacancy on the Board of Directors shall be elected for a term expiring at the annual general meeting of the Company when the term of a director in such Class would otherwise expire."

CERTIFIED A TRUE COPY THE 16TH DAY OF SEPTEMBER, 1998.

DuMoulin Black	(Signature) /s/ David Jennings
10th Floor
595 Howe Street	David Jennings
Vancouver. B.C.	Solicitor
V6C 2T5	(Relationship to Company)

249601\NAME\0974

Exhibit 12.1

In connection with the Transition Report of Dynamic Oil & Gas, Inc. (the Company) on Form 20-F for the nine-month period ending December 31, 2002 as filed with the Securities and Exchange Commission on the date hereof (the Report), I, Wayne J. Babcock, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes Oxley Act of 2002, that:

	1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Wayne J. Babcock

Wayne J. Babcock
President and Chief Executive Officer

Date May 16, 2003

A signed original of this written statement required by Section 906 has been provided to Dynamic Oil & Gas, Inc. and will be retained by Dynamic Oil & Gas, Inc. and furnished to the Securities Exchange Commission or its staff upon request.

Exhibit 12.2

	1.	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Michael A. Bardell

Michael A. Bardell
Chief Financial Officer
(Principal Financial and Accounting Officer)

Date May 16, 2003

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	7th grade Good

Dynamic Oil & Gas (DYOLF) Inactive 20-F2002 FY Annual report (foreign)

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