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UNITED STATESSECURITIES 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
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OR


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

For the fiscal year ended March 31, 2002





OR


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




Commission File Number 0-17551





DYNAMIC OIL & GAS, INC.


(formerly Dynamic Oil Limited)











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








Title of Each Class
   Outstanding at August 19, 2002Common Stock Without Par Value
   20,462,230 Shares  X  No





Indicate by check mark which financial statement item the Company has elected to follow.   Item 17. X   Item 18.





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TABLE OF CONTENTS





PageGlossary of Terms
   3Part I.Item 1.   Identity of Directors, Senior Management and Advisers
   N/AItem 2.   Offer Statistics and Expected Timetable
   N/AItem 3.   Key Information
   6Item 4.   Our Information
   13Item 5.   Operating and Financial Review and Prospects
   31Item 6.   Directors, Senior Management and Employees
   42Item 7.   Major Shareholders and Related Party Transactions
   51Item 8.   Financial Information
   51Item 9.   The Offer and Listing
   52Item 10.  Additional Information
   53Item 11.  Quantitative and Qualitative Disclosures About Market Risk
   62Item 12.  Description of Securities Other than Equity Securities
   64Part II.Item 13.  Defaults, Dividend Arrearages and Delinquencies
   65Item 14.  Material Modifications to the Rights of Security Holders and Use of Proceeds
   65Item 15.  [Reserved]
   n/aItem 16.  [Reserved]
   n/aPart III.Item 17.  Financial Statements
   65Item 18.  Financial Statements
   65Item 19.  Exhibits
   65 2
  Glossary of TermsAir 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 which 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 which 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. 3


|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 which is gradually deviated (usually horizontally to 90
0) 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    | An 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 which 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 which contain a small fossil named Ostracod.                                                                                                                                                                               

4


|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 which 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 which 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 which 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 which 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 back pressure 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 900.                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|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.                                                                                                                                                                                                                                                                                                                                                                                                                                                  




5 Part I.


Item 1.    Identity of Directors, Senior Management and Advisers


Not applicable.


Item 2.    Offer Statistics and Expected Timetable


Not applicable.


Item 3.    Key Information





Selected Financial Data





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





Selected Financial Data Presented According to Canadian GAAPFor the years ended March 31 ($ 000’s)
   2002
   2001
   2000
   1999
   1998Statements of OperationsGross revenues
   26,402
   34,463
   15,770
   9,495
   2,149Net revenues
   14,215
   20,524
   7,438
   3,857
   892Funds flow from operations
   11,337
   18,168
   5,634
   2,634
   (143)Funds flow per share, basic ($)
   0.55
   0.91
   0.29
   0.13
   (0.01)Funds flow per share, diluted ($)
   0.55
   0.89
   0.28
   0.13
   (0.01)(Loss) earnings before taxes
   (5,420)
   14,449
   2,871
   1,212
   (2,361)Net (loss) earnings
   (3,519)
   9,714
   4,079
   1,212
   (2,361)Common shares  weighted avg. (# 000’s)
   20,365
   19,938
   19,710
   19,892
   16,253Net (loss) earnings per share, basic ($)Net (loss) earnings per share, diluted ($)
   (0.17)(0.17)
   0.49 0.48
   0.21 0.20
   0.06 0.06
   (0.15)(0.13)Balance SheetsWorking capital (deficiency)
   (13,281)
   1,969
   (3,716)
   (1,225)
   (4,233)Total assets
   37,152
   29,991
   18,811
   12,487
   13,185Current liabilities
   19,625
   6,210
   7,717
   3,950
   7,532Long-term liabilities
   824
   540
   402
   404
   370Deferred gain on sale
   109
   340
   652
   997
   -Future income tax liability
   -
   2,955
   -
   -
   -Net assetsShare capital
   16,593 20,915
   19,947 20,642
   10,041 20,420
   7,136 21,080
   5,283 20,195Deficit
   (4,322)
   (695)
   (10,379)
   (13,944)
   (14,912)


6 Selected Financial Data Presented According to U.S. GAAP


The following table reflects the major differences in the application of Canadian GAAP and U.S. GAAP:


For the years ended March 31 ($ 000’s)
   2002
   2001
   2000
   1999
   1998Statements of OperationsNet (loss) earnings under Canadian GAAP
   (3,519)
   9,714
   4,079
   1,212
   (2,361)Reconciling adjustments *Compensatory stock options issued
   -
   -
   -
   (8)
   -Options issued for services
   -
   (20)
   -
   -
   -Ceiling test adjustment to natural gas properties
   (216)
   -
   (145)
   -
   -Income taxes
   669
   (577)
   -
   -
   -Net (loss) earnings under U.S. GAAP
   (3,066)
   9,117
   3,934
   1,204
   (2,361)Net (loss) earnings/share, U.S. GAAP basic ($)
   (0.15)
   0.46
   0.20
   0.06
   (0.15)Net (loss) earnings/share, U.S. GAAP diluted ($)
   (0.15)
   0.45
   0.19
   0.06
   (0.13)After adjusting for certain differences, selected balance sheet items under U.S. GAAP would become:Balance SheetsFuture income tax liability
   -
   3,532
   -
   -
   -Share capital *
   21,883
   21,610
   21,368
   21,802
   21,152Deficit
   (5,422)
   (2,356)
   (11,473)
   (14,896)
   (15,869)*For complete explanations of the reconciling adjustments shown below, see Note 11 attached to the Financial      Statements presented under Item 17 to this report.


Dividends





We have never paid or declared dividends on our shares of common stock and we do not intend to do so for 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 average, end, high and low exchange rates for the months indicated and the average exchange rates for the years 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 August 13, 2002 was CDN $1.5658 per  U.S. $1.00.


Exchange Rates for Canadian Versus U.S. Dollars(High/Low Rates for Recent Months)
   High
   LowJuly, 2002
   1.5880
   1.5145June, 2002
   1.5499
   1.5108May, 2002
   1.5708
   1.5275April, 2002
   1.5995
   1.5632March, 2002
   1.5958
   1.5767February, 2002
   1.6112
   1.5885


7  Exchange Rates for Canadian Versus U.S. DollarsYears Ended March 31
   Average ($)2002
   1.572001
   1.502000
   1.471999
   1.501998
   1.40





Capitalization and Indebtedness





Not applicable.





Reasons for the Offer and Use of Proceeds





Not applicable.





Risk Factors





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 which 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 fiscal 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


8 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, which 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 four-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 as compared with losses of $2,361,280 and $910,926 in fiscal years 1998 and 1997, respectively.  In fiscals 2000 and 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.  As of March 31, 2002, we had an accumulated deficit of $4,321,539.  Our future viability must continue to 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, 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.  Our future growth is partially 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











Dependence on One Major Property











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


9





Exploration and Development Risks











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











Drilling and Operating Risks








10     Drilling Plans Subject to Change











Replacement of Reserves











Dependence on Few Customers











Reserves








Shortage of Supplies and Equipment





Our ability to conduct operations in a timely and cost effective manner is subject to the availability of oil and gas 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.





11
Government Regulation and Environmental Matters











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.











Interruption From Severe Weather











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.








12


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.  Our telephone number is (800) 663-8072.


Capital Expenditures and Exploration Expenses Over the Past Three Years


Over the past three fiscal years, our capital expenditures aggregated $39.4 million, with the major expenditures as follows:


|$ |  | $14.7 million for the acquisition of additional working interest holdings in our producing assets at St. Albert, Alberta.  Through this acquisition, our interests increased to 75% from 50% in the majority of gas-related assets and to 75% from 25% in all oil-related assets;
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|$ |  | $7.8 million on the continuing development of the St. Albert, Alberta, Canada  property.  This money was spent on drilling, re-completing and tying-in of natural gas wells, as well as constructing several new production-enhancing facilities;
|- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|$ |  | $8.3 million on land acquisitions, exploratory drilling and facilities construction at Peavey/Morinville in Alberta, Canada; and
|- |  | --------------------------------------------------------------------------------------------------------------------------------

|$ |  | $2.9 million (net) on land acquisitions and exploration of a prospective natural gas property at Orion in northeast British Columbia, Canada.
|- |  | ---------------------------------------------------------------------------------------------------------------------------------------------

During the last three fiscal years, we spent $7.9 million on exploration expenses.  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.  The $7.9 million is itemized as follows:


|$ |  | $5.5 million on unsuccessful drilling attempts;
|- |  | -----------------------------------------------

|$ |  | $1.9 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 Fiscal 2003





On April 11, 2002, our Board of Directors approved our capital budget which authorized us to spend a total of $17.0 million in capital expenditures for fiscal 2003 as follows:


$$0.7 million for the acquisition of new prospective lands in the central region of Alberta and in the northeastern region of British Columbia; $$7.3 million on drilling, re-completions, tie-ins and facilities at St. Albert, our main property in central Alberta; $$1.5 million on drilling, tie-ins and facilities on our properties at Halkirk in central Alberta; $$6.0 million on exploratory drilling and tie-ins on our land interests at Orion and Cypress (see Recent Material Event below) in northeastern British Columbia; and $$1.5 million on drilling on two central Alberta land interests owned by us.





We have also approved an exploration expense budget of $1.1 million to acquire seismic data on our land interests in central Alberta and northeastern British Columbia.


13


We expect funds for our capital expenditure and exploration expense plans for fiscal 2003 to be sourced from funds flow from our operations and from our bank credit facility (see Note 3 to the Financial Statements under Item 17 in this report).  In the event that our funding sources are insufficient to accomplish the expenditure and exploration plans for fiscal 2003, we will be forced to curtail certain of such expenditures.





Recent Material Event





On June 10, 2002, we announced our Farmout and Option Agreement (the Farmout Agreement) in the Orion area of northeastern British Columbia.  Under the terms of the Farmout Agreement, the farmee will have the right to earn a sliding scale interest in three designated blocks of our Orion acreage, comprising 28,334 gross acres (21,665 net) by drilling up to four horizontal test wells into the Upper Devonian Age, Jean Marie formation.  The first well, a commitment well, must be drilled by September 30, 2002.  To continue earning under the Farmout Agreement, the farmee has sixty days from rig release date of the first well to commit to drill the first of three option wells.  The first option well must be drilled by April 15, 2003.  The second and third option wells must be drilled by April 15, 2004.  Upon completion of the terms of the Farmout Agreement, we will retain an interest in the three blocks ranging from 20% to 50%, with a net average working interest of approximately 32%.  We continue to hold a total of 1,669 gross acres (1,669 net) in the Orion area that is not subject to the Farmout Agreement.





On July 30, 2002, we announced our Participation and Farmin Agreement (the Farmin Agreement) in the Cypress area of northeast British Columbia.  Under the Farmin Areement, we will have the right to earn a net average working interest of 35% in two out of eight land blocks comprising approximately 5,120 acres, by paying 50% of the cost to drill two test wells.  The first well, a commitment well and the second an option well, are expected to cost us $1.3 million and $0.9 million, respectively.  Upon completion of the terms of the Farmin Agreement, we will have the right to earn a 50% working interest in the two test-well land blocks, subject to a convertible 15% gross overriding royalty, and a 30% working interest in the remaining six land blocks.





Share Repurchases











Business Overview


General


Our principal business is acquiring, exploring and developing natural gas and oil properties.  Our natural gas and 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 oil.  We intend to continue this type of business activity.





Concentration of Commodities





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








14





$the proximity of hydrocarbon pipelines or other economically-feasible transportation; $the availability of pipeline capacity; $the demand for hydrocarbons 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 hydrocarbons within Canada.











Concentration of Operations











Revenue Breakdown





During the past three fiscal years, our total revenue was $76.6 million.  Of this total, 79% came from the sales of natural gas, 18% came from the sales of natural gas liquids and 3% came from the sales of 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 fiscal years is shown in the table below:


Natural gas, liquids and oil sales $(000’s)
   2002
   2001
   2000Natural gas
   20,944
   28,006
   11,660Natural gas liquids
   4,442
   5,935
   3,620Oil
   1,016
   522
   490Total
   26,402
   34,463
   15,770


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





We market our natural gas through direct sales and through the use of aggregators.  Aggregators, when used, act as our marketing agents selling natural gas for us via a mix of spot, short term (less than one year) and long term


15 contracts.  We cannot affect the mix of spot, short term and long term contracts that are managed by aggregators, nor are we privy to the exact amount of volume sold into each contract type throughout the year.  Based on information provided by aggregators, the table below approximates our mix of contract types for each of the past three fiscal years.





Of our total gas sold during fiscal 2002, 53% was sold into aggregator portfolios.    The remaining 47% was sold directly by us into the spot market.  In fiscal years 2001 and 2000, the percentage of total gas sold to aggregators was 77% and 86%, respectively, with the remainder sold by us in the spot market.  The percentage of total gas sold into aggregator portfolios decreased by 24% in fiscal 2002 from fiscal 2001 due mainly to the fact that in fiscal 2002 we sold more natural gas into the spot market.





The table below combines all contract types, aggregated and not-aggregated, to approximate the percentage of our natural gas being sold into each contract type in each of the three fiscal years.


Approximate mix of gas contract types
   2002
   2001
   2000Spot market  not aggregated
   47%
   23%
   14%Spot market  aggregated
   27%
   19%
   22%Total spot market
   74%
   42%
   36%Short-term  aggregated (less than one year)
   1%
   9%
   11%Long-term  aggregated
   25%
   49%
   53%Total
   100%
   100%
   100%








During fiscal 2002, we increased our percentage of total natural gas sales exposed to spot market pricing by approximately 76% over fiscal 2001.  The main reason for this significant increase is the sales of new natural gas production generated from the St. Albert acquisition into the spot market in fiscal 2002.  Although the percentage of total natural gas sales exposed to spot market activity increased, weighted average spot prices of natural gas declined in fiscal 2002 from fiscal 2001, thereby contributing to a decrease in total revenues (see Natural Gas, Liquids and Oil Revenues below).  Total gas sales exposed to spot market pricing in fiscal 2001 increased by 17% over fiscal 2000.





Supply Contracts or Agreements








Competition





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.


16


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; $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 SaskatchewanSt. Albert
   Orion (northeastern B.C.)
   ElmorePeavey/Morinville
   Cypress (northeastern B.C.
   RapdanWestlock
   Fraser Valley (southwestern B.C.)SimonetteRedwaterVirgoStanmoreHalkirkAlexanderQuirk Creek (Foothills)


As shown in the table below, our land holdings as of March 31, 2002 total 150,171 gross acres and 86,251 net acres.  Our weighted average working interest in all of these properties was approximately 57%.  The remaining 43% was held by joint venture, industry partners who share a common interest in exploring or developing the property in question.  Of total land holdings as of March 31, 2002, our developed acreage comprises 24,110 gross acres (17,089 net) and our undeveloped acreage comprised 126,061 gross acres (69,162 net).  In fiscals 2001/2000, our total developed acreage comprised 18,175/16,103 gross acres and 11,078/9,184 net acres, respectively, while our total undeveloped acreage comprised 126,271/103,097 gross acres and 78,949/55,752 net acres, respectively.  Our weighted average working interest in all properties was 63% in fiscal 2001 and 54% in fiscal 2000.








Land Holdings (acres)As at March 31, 2002
   Developed
   Undeveloped
Total
   Weighted AverageArea
   Gross
   Net
   Gross
   Net
   Gross
   Net
   Working InterestHalkirk
   3,840
   3,456
   3,200
   3,200
   7,040
   6,656
   95%Peavey/Morinville
   7,363
   5,037
   6,630
   4,405
   13,993
   9,442
   67%St.Albert
   9,057
   5,884
   6,293
   4,319
   15,350
   10,203
   66%Quirk Creek
   -
   -
   19,040
   9,520
   19,040
   9,520
   50%Orion
   -
   -
   30,003
   23,334
   30,003
   23,334
   78%Fraser Valley
   -
   -
   54,332
   18,109
   54,332
   18,109
   33%Other Alberta
   3,850
   2,712
   6,563
   6,275
   10,413
   8,987
   86%Total
   24,110
   17,089
   126,061
   69,162
   150,171
   86,251
   57%  
  17


St. Albert, Alberta





Property Description


St. Albert/Big Lake is located in central Alberta near the City of Edmonton.  The area is prospective for remaining recoverable oil from six established oil pools within the Leduc (D-3), Nisku (D-2) and Wabamun (D-1) formations.  These formations are underlyingmultiple pools of stacked, natural gas-bearing sandstones of Cretaceous Age draped over two, underlying reef structures.  We own a weighted average working interest of 66% in 15,350 gross acres (10,203 net) of land including 6,293 gross undeveloped acres (4,319 net).  In addition, we also own a weighted average 66% share of various overriding royalty interests associated with an additional 4,729 gross acres (3,121 net).





Acquisition Activity in Fiscal 2002


Effective April 1, 2001 as announced on June 29, 2001, we increased our interest at St. Albert under a purchase and sale agreement with Fletcher Challenge Oil & Gas, Inc. (Fletcher).  Under the agreement, we acquired 50% of Fletcher’s interest in the shallow gas wells and facilities and 67% of Fletcher’s interest in the oil wells and facilities and assumed the duties of Operator effective June 30, 2001.





Wells and facilities


As of the end of fiscal 2002, we owned and operated a 75% working interest in fourteen producing gas wells, six producing oil wells and various working interests ranging between 25% - 83% in four other producing gas wells, five suspended potential gas wells and six additional wells awaiting further evaluation.  We own a 25% interest in a ten-mile sales gas pipeline system and in a significant gas processing facility capable of processing 15 mmcf/d of sour gas and 15 mmcf/d of sweet gas.  Further, we own a 75% interest in an oil battery capable of processing 2,400 boe/d.





In fiscal 2002, we conducted re-entry/workover operations on five previously suspended or low production wells resulting in four natural gas wells and one unsuccessful attempt.  Over the past three years, we focused exploration and development at St. Albert on shallow gas prospects until we pursued a new oil target within the established Devonian Age pools by drilling a successful Nisku (D-2) oil well in February 2002.  By the end of fiscal 2002, the Nisku well had averaged 89 boe/d over a 57-day production period.





Production and Reserves


We increased our average daily production rates at St. Albert in fiscal 2002 by 547 boe/d or 25%, to 2,717 boe/d over fiscal 2001.  The increase was primarily due to the acquisition of an additional interest from Fletcher.  Production increases at year-end came as a result of a modification to a sour compressor facility and the successful workover of five previously suspended or low producing wells.  We exited the year producing 3,224 boe/d from the St. Albert field.   At the close of fiscal 2002, our independent proved natural gas, natural gas liquids and oil reserves were estimated at 7,201 mboe and risked probable reserves were estimated at 338 mboe.





Fiscal 2003 Plans


Historically, St. Albert has produced in excess of 23 million barrels of oil and 83,000 mmcf of raw gas.  Prospectively, we identified several potential targets for additional oil and gas recovery on the property.  We have budgeted eight new wells at St. Albert in fiscal 2003, six wells targeting the remaining oil potential in the established oil pools and two wells targeting new gas reserves.





Peavey/Morinville, Alberta





18

Property Description


Peavey/Morinville is approximately nineteen kilometres north of the City of Edmonton.  The area is prospective for multiple oil and natural gas-bearing sandstones of Cretaceous Age.  These sands are stratigraphically controlled and structurally draped over highs in the Leduc reef.  Presently, we own a weighted average 67% working interest in approximately twenty-six square kilometers of 3-D seismic data and 13,993 gross acres (9,442 net) of land including 6,630 gross acres (4,405 net) of undeveloped land.





Wells and Facilities


We operate and hold a weighted average working interest of 77% in seven producing gas wells in this area and 100% working interest in a 5.5 mmcf/d compression/dehydrator facility.  At the end of fiscal 2002, approximately 0.8 mmcf/d of third party production was being processed through this facility.  We hold various working interests ranging between 35% and 96% in eleven shut-in or suspended gas wells, one potential oil well and two wells awaiting abandonment.





Production and Reserves


The average annual daily production rate from the property remained steady between fiscals 2001 and 2002 at close to 290 boe/d.  However, due to the unexpected influx of water, the year-end exit rate in fiscal 2002 decreased by 269 boe/d or 62%, to 165 boe/d from fiscal 2001.  As a result, our independent estimate of proved reserves was revised downward in fiscal 2002 by 1,143 mboe or 61%, to 742 mboe from fiscal 2001.





Fiscal 2003 Plans


Presently, we are examining ways to maximize the value in this property.  The property contains a substantial network of pipelines including a gas compression facility, eleven shut-in or suspended gas wells, 6,630 gross acres of undeveloped land and is covered by approximately twenty-six square kilometres of 3-D seismic data.  Among the possibilities, we are considering the property as prospective for coal bed methane development.





Halkirk Area, Alberta





Property Description


Halkirk is located approximately one hundred and seventy kilometers northeast of the City of Calgary, Alberta. The area is prospective for the development of three sweet gas horizons: the Belly River, Viking, and Hackett formations. The primary target for reserves is the Viking C sand with an average net pay thickness of 5.3 meters.  The area is also close to existing gas processing facilities.  We own a weighted average 95% working interest in 7,040 gross acres (6,656 net) of land including 3,200 gross undeveloped acres (3,200 net).  We increased our land holdings in the area by 2,880 gross acres (2,880 net) during fiscal 2002.





Wells and Facilities








Production and Reserves


Production from the field began in late October 2001 and closed out fiscal 2002 averaging 252 boe/d.  Fiscal 2002 independent, proved natural gas reserves were estimated at 595 mboe and risked probable reserves were estimated at 313 mboe.





Fiscal 2003 Plans








Quirk Creek





Property Description .


19


Exploration Activity








Fiscal 2003 Plans








Orion, NE British Columbia





Property Description


Orion is strategically located between the Sierra and Helmet natural gas fields.  Located near Kotcho Lake, the acreage is approximately fifty-six kilometers west of the Alberta border and one hundred and twelve kilometers south of the Northwest Territories.  The property is dissected by the Sierra Yoyo Desan Road, which provides year-round access for drilling operations.  The Jean Marie formation is considered to be a regional platform carbonate with extensive patch-reef development at sub-surface depths of between 1,000  1,400 meters.  The formation averages one hundred and ninety meters thick and is draped over deep-seated substructures.  A prolific open fracture network enhances reservoir permeability.  As at the end of fiscal 2002, we held a weighted average working interest of 78% in 30,003 gross acres (23,334 net) of undeveloped land.





Wells and Facilities


We own a working interest of 100% in one suspended potential natural gas well.  In fiscal 2002, we perforated and tested the Bluesky and Wabamun formations in the well.  It is currently suspended as a potential natural gas well pending further evaluation and development of a sales pipeline system.  The property is located at the termination of two major pipeline systems.  The Duke Energy Pipeline System is located seven kilometers south of the property and connects to Fort Nelson, further extending south to Washington State.  A second pipeline, the Duke Energy Field Services Pipeline System, is accessible on the north boundary of the property and connects to Tooga Compressor Station, further extending east to Alberta.





Fiscal 2003 Plans


On June 10, 2002 we announced the terms of a Farmout and Option Agreement with a large independent Canadian oil and gas company (the farmee) on the Orion property.  Under the terms of the Farmout and Option Agreement, the farmee will have the right to earn a sliding scale interest in three designated blocks of the farmee’s Orion acreage comprising 28,334 gross acres (21,665 net) by drilling up to four horizontal test wells into the Upper Devonion Age, Jean Marie formation.  The first well, a commitment well, must be drilled by the end of September 2002.  To continue earning under the Farmout Agreement, the farmee has sixty days from rig release date of the first well to commit to drill the first of three option wells.  The first option well must be drilled by April 15, 2003.  The second and third option wells must be drilled by April 15, 2004.





Fraser Valley, British Columbia





Property Description


Permit 802, located in the southwestern area of the Province of British Columbia, includes all petroleum and natural gas rights onshore in an area known as the Fraser Valley and in adjacent offshore area.  Although structural control is limited, government gravity and proprietary on-shore seismic data support the presence of a large structural feature approximately nineteen square kilometers in area lying just offshore within the boundaries of the Permit.20


Fiscal 2002 Project Status


We were inactive in the Fraser Valley during fiscal 2002.  Under a joint venture agreement with Conoco Canada Limited, we continue to own a 33% working interest in approximately 54,332 gross undeveloped acres (18,109 net) of onshore and offshore petroleum and natural gas rights associated with Permit 802, a validated British Columbia Exploration Permit.

















Other Alberta Properties











Reserves of Natural Gas, Natural Gas Liquids and Oil





Our independent reserve estimates effective April 1 for each of the last three fiscal years prepared by Status Engineering Associates of Calgary, Alberta (Status) are shown in the following tables:


Petroleum and natural gas reserves(Before royalties)
   Natural Gas
   NGL’s / Oil
   Equivalent*Fiscal 2002
   (mmcf)
   (mbbls)
   (mboe)Proved producing
   31,099
   1,908
   7,091Proved non-producing
   8,972
   229
   1,724Probable (50% risked)
   4,669
   321
   1,099Total Fiscal 2002
   44,740
   2,458
   9,915Fiscal 2001Proved producing
   30,885
   1,387
   6,535Proved non-producing
   8,586
   127
   1,558Probable (50% risked)
   6,326
   27
   1,081Total Fiscal 2001
   45,797
   1,541
   9,174Increase (decrease) % (net of production) from 2001 to 2002
   (2%)
   60%
   8%Fiscal 2000Proved producing
   29,243
   1,758
   6,632Proved non-producing
   11,518
   448
   2,368Probable (50% risked)
   4,004
   11
   678Total Fiscal 2000
   44,765
   2,217
   9,678Increase (decrease) % (net of production) from 2000 to 2001
   2%
   (31)%
   (5)% * Natural gas is converted into barrels of oil equivalent on the basis of 6 mcf = 1 barrel.


21
































During fiscal 2001, estimated reserves of natural gas increased (net of annual production) by 2% over fiscal 2000.  Of the fiscal 2001 increase in natural gas reserves, most of it was lower in natural gas liquids content than gas reserves of fiscal 2000, which explains the 31% decrease of reserves of natural gas liquids between the two years.


Petroleum and natural gas reserves reconciliationsNatural Gas
   NGL’s/Oil
   Equivalent(mmcf)
   (mbbls)
   (mboe)Opening reserves, fiscal 2000
   44,765
   2,217
   9,678Revisions of Previous Estimates
   (2,351)
   (497)
   (889)Production *
   (4,557)
   (206)
   (965)Extensions and discoveries
   7,940
   27
   1,350Reserves, fiscal 2001
   45,797
   1,541
   9,174Acquisitions
   12,359
   804
   2,864Revisions of Previous Estimates
   (9,185)
   (38)
   (1,569)Production *
   (5,514)
   (258)
   (1,177)Extensions and discoveries
   1,283
   409
   623Year end reserves, fiscal 2002
   44,740
   2,458
   9,915*For production history of fiscal years 2001 and 2000, see section entitled, Production Volumes under Item 5, Operating and               Financial Review and Prospects in this report.








Discounted net present value $(000’s)(Before taxes, after royalties)
   0%
   10%
   15%
   20%Proved producing
   87,581
   59,874
   52,110
   46,344Proved non-producing
   18,242
   10,608
   8,513
   6,984Total proved
   105,823
   70,482
   60,623
   53,328Total probable
   10,687
   6,044
   4,616
   3,522Total proved and probable, fiscal 2002
   116,510
   76,526
   65,239
   56,850Total proved and probable, fiscal 2001
   224,918
   142,273
   120,047
   103,873Total proved and probable, fiscal 2000
   84,231
   54,404
   46,107
   39,960


22In determining the NPV at the end of fiscal 2002, Status used a constant estimated natural gas price of $3.77/mcf, based on 1,000 BTU per standard cubic foot.  For oil, a constant estimated price of $29.35/barrel was used, based on 40API oil priced at $30.90 at Edmonton, Alberta.  These prices represent Status’ expectations of our weighted average prices achievable over the nine-month period April to December 2002, using contract terms and conditions in existence at our March 31, 2002 fiscal year end.  Our actual weighted average prices for the month of March 2002 were $3.24/mcf for natural gas and $33.27/barrel for oil.





At the end of fiscal 2002, our estimated 10% discounted NPV of proved and 50% probable reserves was $76.5 million.  This represents an estimated NPV of $3.74 per share (weighted average number of shares of common stock outstanding as at March 31, 2002 = 20.5 million, basic).





At the end of fiscal 2001, our estimated 10% discounted NPV of proved and 50% probable reserves was $142.3 million, based on estimated constant prices of $7.22/mcf for natural gas and $38.18/bbl for oil.  This represented an estimated NPV of $7.14 per share (weighted average number of shares of common stock outstanding as at March 31, 2001 = 19.9 million, basic).  Our actual weighted average prices for the month of March 2001 were $6.75/mcf for natural gas and $41.19/bbl for oil.





At the end of fiscal 2000, our estimated 10% discounted NPV of proved and 50% probable reserves was $54.4 million, based on estimated constant prices of $2.80/mcf for natural gas and $28.00/bbl for oil.  This represented an estimated NPV of $2.76 per share (weighted average number of shares of common stock outstanding as at March 31, 2000 = 19.7 million, basic).  Our actual weighted average prices for the month of March 2000 were $3.14/mcf and $40.44/bbl for oil.








2324252627282930


Item 5.    Operating and Financial Review and Prospects





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



































For comparison purposes, discussion and analysis provides, in tabular form, our operating and financial results for the years ended March 31, 2002, 2001 and 2000.





31      Operating Results





Field Drilling Activity








Drilling Activity2002
   2001
   2000Gross
   Net
   Gross
   Net
   Gross
   NetGas completions
   7
   6.1
   11
   8.7
   4
   3.6Potential/suspended gas wells
   2
   1.4
   3
   2
   -
   -Oil completions
   1
   0.7
   1
   0.9
   -
   -Dry and abandoned
   4
   2.8
   2
   1.9
   2
   1.2Total
   14
   11.0
   17
   12.5
   6
   4.8Success rate
   
   75%
   
   85%
   
   75%








Summary of Operating and Financial Results





Unless otherwise noted, amounts in the following discussion and analysis tables are in thousands of Canadian dollars, and production volumes are before royalties.




















Increase (decrease) in revenues resulting from variances in:
   2002 Compared to:2001
   %
   2000
   %Natural gasPrice
   (10,791)
   (134)
   4,740
   45Volume sales
   3,728
   46
   4,544
   43Natural gas liquidsPrice
   (2,197)
   (27)
   494
   4Volume sales
   705
   9
   328
   3OilPrice
   (85)
   (1)
   77
   1Volume sales
   579
   7
   449
   4Total
   (8,061)
   (100)
   10,632
   100


32






































Funds flow from operations, earnings
   2002
   2001
   2000and return on equity *
   Total
   % Change
   Total
   % Change
   TotalFunds flow from operations
   11,337
   (38)
   18,168
   222
   5,634- per share ($)
   0.55
   (40)
   0.91
   213
   0.29Net (loss) earnings
   (3,519)
   (136)
   9,714
   138
   4,078- per share ($)
   (0.17)
   (135)
   0.49
   133
   0.21Shareholder’s equity
   16,593
   (17)
   19,946
   99
   10,040Average (loss) return on equity (%)
   (21)
   (143)
   49
   20
   41


*  When comparing these particular measurements with those of other industry members, see comments relating to facilities leasing costs inProduction Costsbelow.














33























Volumes, Prices, Gross Revenues, Royalties, Operating Costs, Administrative Costs and Other


Production Volumes


In fiscal 2002, daily production volumes increased over fiscal 2001 by an average of 581 boe per day or 22%, to 3,225 boe per day.  This was due to increases in natural gas production of 437 boe per day, in natural gas liquids production of 101 boe per day, and in oil production of 43 boe per day.  Of our total annual production of 1,177 mboe in fiscal 2002, 78% was natural gas compared to 79% of fiscal 2001’s total 965 mboe and 76% of fiscal 2000’s total 947 mboe.








Daily production rates and
   2002
   2001
   2000total annual production
   Average
   % Change
   Average
   % Change
   AverageNatural gas (mcf/d)
   15,107
   21
   12,486
   6
   11,798Natural gas liquids (bbls/d)
   631
   19
   530
   (9)
   585Oil (bbls/d)
   76
   130
   33
   (21)
   42Equivalent (boe/d)
   3,225
   22
   2,644
   2
   2,593Total annual production (mboe)
   1,177
   22
   965
   2
   947Gas weighting (%)
   78
   
   79
   4
   76


Product Prices


In fiscal 1998, we signed a long-term, firm-service sales contract regarding our St. Albert natural gas production.  Spot market sales at that time were limited to our production of natural gas liquids.  Since then, we have sold other available natural gas production directly into the spot market.








Weighted average prices
   2002
   2001
   2000Average
   % Change
   Average
   % Change
   AverageNatural gas ($/mcf)
   3.81
   (39)
   6.22
   129
   2.72Natural gas liquids ($/bbl)
   19.30
   (37)
   30.64
   80
   16.98Oil ($/bbl)
   34.33
   (21)
   43.60
   38
   31.53Equivalent ($/boe)
   22.26
   (38)
   35.66
   113
   16.74


* See Item 4 Our Information  Business Overview  Marketing for information on our mix of gas contract types.


34


To date, we have not undertaken any derivative or hedging activities.


Natural Gas, Liquids and Oil Revenues


Total revenues in fiscal 2002 decreased by $8.1 million or 23%, to $26.4 million from fiscal 2001.  Due to higher volume sales of all commodities in fiscal 2002, total revenues increased by $5.0 million or 62% over fiscal 2001 (see variance analysis table above in Summary of Operating and Financial Results under Item 5 in this report).  Offsetting this increase wasa decrease in total revenues from all products of $13.1 million or 162% caused by the variance in weighted average prices of all commodities for fiscals 2002 and 2001.








Natural gas, liquids and oil gross revenues
   2002
   2001
   2000Total
   % Change
   Total
   % Change
   TotalNatural gas
   20,944
   (25)
   28,006
   140
   11,660Natural gas liquids
   4,442
   (25)
   5,935
   64
   3,620Oil
   1,016
   95
   522
   7
   490Total
   26,402
   (23)
   34,463
   119
   15,770  Royalties


The amount that we must pay in terms of royalties and mineral taxes is closely related to our realized weighted average commodity prices.  In general, therefore, a trend exists between these items.  Total royalties including mineral taxes decreased in fiscal 2002 by $3.0 million or 32%, to $6.3 million from fiscal 2001 (see Item 5  Operating Results - Product Prices under Item 5 in this report).
































35       Royalties and mineral taxes
   2002
   2001
   2000Total
   % Change
   Total
   % Change
   TotalCrown
   1,317
   (55)
   2,958
   182
   1,050Freehold and overriding
   4,067
   (33)
   6,106
   113
   2,872Freehold mineral taxes *
   1,116
   41
   794
   48
   5356,500
   (34)
   9,858
   121
   4,457ARTC
   (159)
   68
   (499)
   -
   7Total
   6,341
   (32)
   9,359
   110
   4,464


*  Based on curent industry trend, we reclassified mineral taxes from Production costs to Royalties in fiscal 2002.  For comparison purposes, prior year amounts have been restated in the Statements of Operations and Deficit in the Financial Statements under Item 17 of this report.


Production Costs


Of our total production costs in fiscal 2002, 82% were incurred at St. Albert.  Corporate unit production costs of $4.97 per boe were therefore influenced mostly by St. Albert.  Unit production costs at St. Albert in fiscal 2002 were $4.84 per boe compared to $4.77 per boe in fiscal 2001, an increase of 1%.  In fiscal 2000, St. Albert unit production costs were $4.05 per boe.


Production costs
   2002
   2001
   2000Total
   % Change
   Total
   % Change
   TotalProduction costs * - total
   5,846
   28
   4,580
   24
   3,690Per boe ($)
   4.97
   5
   4.75
   20
   3.90 
 *  Based on curent industry trend, we reclassified mineral taxes from Production costs to Royalties in fiscal 2002.  For comparison purposes, prior year amounts have been restated in the Statements of Operations and Deficit in the Financial Statements under Item 17 of this report.


*  Based on curent industry trend, we reclassified mineral taxes from Production costs to Royalties in fiscal 2002.  For comparison purposes, prior year amounts have been restated in the Statements of Operations and Deficit in the Financial Statements under Item 17 of this report.











In fiscal 2002, facilities leaseback costs totaled $0.9 million or $0.84 per boe.  Comparatively, facilities leaseback costs in fiscal 2001 totaled $1.4 million or $1.38 per boe.  In fiscal 2000 , they totaled $1.5 million or $1.58 per boe.  After taking into account unit facilities leaseback costs, unit production costs in fiscal 2002 were $4.13 per boe ($4.97 less $0.84).  Comparatively, unit production costs were $3.37 per boe ($4.75 less $1.38) in fiscal 2001 and $2.32 per boe ($3.90 less $1.58) in fiscal 2000.  On this basis, unit production costs in fiscal 2002 increased by $0.76 per boe or 23% over fiscal 2001.





One key reason for the increased unit production costs in fiscal 2002 over fiscal 2001 is that increased natural gas production through the St. Albert acquisition is high in liquid content, therefore, more costly to produce.  Simultaneously, natural gas production very low in liquid content from the Peavey/Morinville field decreased during fiscal 2002, thereby adding to the overall unit production cost increase.  In addition, the cost of utilities during fiscal 2002 was higher than in fiscal 2001.











According to the 2002 Canadian Energy Survey prepared by PricewaterhouseCoopers, the industry unit production cost average for calendar 2001 is $6.63 per boe for conventional oil and gas trusts and $6.11 per boe for the top 100 Canadian Exploration and Production companies ranked by gross revenues.








36General and Administrative Expenses


Total general and administrative expenses increased in fiscal 2002 by $0.8 million or 50%, to $2.3 million.  During the year, we completed the St. Albert acquisition and became Operator of the property.  As Operator, we took on significant new responsibilities requiring broader staff coverage and outside services.  Due mostly to the hiring of four new staff, salaries and benefits increased by $0.5 million in fiscal 2002.  Also due to the St. Albert acquisition, interest, insurance and professional fees increased in fiscal 2002 over fiscal 2001.








Interest Expense on Operating Loan


During fiscal 2002, our bank revised our revolving, demand credit facility.  The amount of the facility increased from $10 million to $25 million and then decreased to $21 million.  The facility is collateralized by a general assignment of book debts and a floating charge debenture of $35 million.  The interest rate charged by our bank in fiscals 2002, 2001 and 2000 was the federal prime rate established by the Bank of Canada, plus 3/8%.




















Financing costs
   2002
   2001
   2000Total
   % Change
   Total
   % Change
   TotalInterest expense on operating loan *
   495
   106
   240
   24
   194Funds flow times interest coverage
   23
   (70)
   76
   162
   29Average cost per boe ($)
   0.42
   68
   0.25
   19
   0.21 *  See Notes 1 and 3 to the Financial Statements under Item 17 in this report for further details on EIC-122 and the Operating loan.





Ceiling Test, Amortization and Depletion


We annually conduct a ceiling test in accordance with accounting guidelines applicable to the operations of all oil and gas companies that follow the successful efforts method of accounting.  The test prescribes that the carrying value of petroleum and natural gas properties shall be limited to their estimated future net revenues from proved producing reserves less well reclamation costs.














37














Amortization and Depletion
   2002
   2001
   2000Total
   % Change
   Total
   % Change
   TotalAmortization and depletion expense (A&D)
   5,336
   72
   3,097
   100
   1,551Ceiling test adjustments
   6,783
   -
   36
   (61)
   93Total A&D *
   12,119
   287
   3,133
   91
   1,644Assets attracting A&D
   47,525
   112
   22,435
   54
   14,566Total assets
   49,907
   67
   29,874
   54
   19,356Percent of assets attracting A&D to total assets
   95
   27
   75
   -
   75Ratio of A&D to assets attracting A&D
   1:4
   
   1:7
   
   1:9











Exploration Expenses


Our exploration expenses in fiscal 2002 increased by $2.7 million or 142%, to $4.6 million over fiscal 2001.  The most significant increase in exploration costs was due to the expensing of drilling costs associated with unsuccessful wells that were drilled during fiscal 2002 and prior.


























38Gain on Sale of Natural Gas and Oil Interests


In fiscal 2002, we had no significant transactions to report. In fiscal 2001, we sold a 50% interest in a portion of our Orion leases in northeast British Columbia in exchange for a farmin agreement with another company.  The proceeds on the sale were $1.0 million and the associated gain amounted to $0.6 million.  In fiscal 2000, there were no gain or loss on sale transactions to report.


Income Taxes


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.








Income tax pools available
   2002
   2001
   2000
   Maximum annual deductionCanadian exploration expense
   -
   -
   5,219
   100%Non-capital losses
   -
   -
   318
   100%Share issue costs
   -
   -
   95
   100%Canadian development expense
   3,772
   3,307
   1,732
   30%Undepreciated capital costs
   10,297
   5,554
   3,274
   20%  100%Canadian oil and gas property expense
   16,471
   3,986
   4,460
   10%Total
   30,540
   12,847
   15,098  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








Government Policies








Liquidity and Capital Resources


Liquidity


As at March 31, 2002, we had a working capital deficit of $13.3 million that included a balance owing to our corporate bank of $14.8 million under an operating loan.  This resulted in a net debt years-to-repay ratio for fiscal 2002 of 1.2:1.  Comparatively, the net debt years-to-repay ratios for fiscals 2001 and 2000 were nil and 0.7:1, respectively.





39














Debt and future items, to funds flow
   2002
   2001
   2000(Years-to-repay ratios)
   Total
   % Change
   Total
   % Change
   TotalFunds flow from operations
   11,337
   (38)
   18,168
   222
   5,634Working capital
   (13,281)
   (775)
   1,969
   153
   (3,716)Years to repay net debt
   1.2:1
   
   -
   
   0.7: 1Future removal and site restoration
   (824)
   (53)
   (540)
   (34)
   (402)Future facilities leasing commitments *
   (468)
   68
   (1,453)
   (48)
   (2,788)Net debt adjusted for future items
   (14,573)
   -
   (24)
   100
   (6,906)Years to repay net debt & future items
   1.3:1
   
   -
   
   1.2:1 
 * We intend, during fiscal 2003, to exercise our option to purchase the assets under lease for a price of $780,000.  (See Notes 4 and 12 to the Financial Statements under Item 17 in this report for further details on our St. Albert gas facility operating lease commitments).








During fiscal 2002, we repurchased in the open market and canceled 178,800 shares of common stock for $0.3 million.  During fiscal 2001, we repurchased in the open market and canceled 897,300 shares of common stock for $1.5 million.  (See Note 14 to the Financial Statements under Item 17 in this report for details of a bid authorization dated beyond the fiscal year ended March 31, 2002).








Financial Instruments




















Capital Expenditures

















40
 
 Capital expenditures
   2002
   % Change
   2001
   % Change
   2000Drilling, completions and tie-ins
   7,678
   11
   6,939
   150
   2,777Facilities
   1,757
   (50)
   3,522
   245
   1,022Land acquisitions
   12,560
   1105
   1,042
   (43)
   1,828Field expenditures
   21,995
   91
   11,503
   104
   5,627Furniture, fixtures and computer
   116
   47
   79
   (21)
   100Total
   22,111
   91
   11,582
   102
   5,727
 
 Outlook for Fiscal 2003
 
 
 
 
 
 
 
 
 
 
 Sensitivity Analysis
 
 
 Sensitivity AnalysisChanges in
   
   Effect on Funds flowVolume
   Price
   Rate
   
   $(000’s)
   $/shareNatural gas production (mmcf/d)
   1
   -
   -
   
   1,389
   0.070Natural gas price ($/mcf)
   -
   0.10
   -
   
   547
   0.027Natural gas liquids (bbls/d)
   100
   -
   -
   
   704
   0.034Natural gas liquids ($/bbl)
   -
   1.00
   -
   
   230
   0.011Interest rate (%)
   -
   -
   1
   
   33
   0.002 41       Item 6.    Directors, Senior Management and Employees
 
 Directors and Senior Management
 The following is information regarding our Directors, Senior Management and Employees as of March 31, 2002.
 Name
   Position Held
   Age
   ResidenceDirectors and Executive Officers:Wayne J. Babcock
   President & CEO, Director
   59
   Vancouver, B.C.Donald K. Umbach
   Vice President & COO, Director
   48
   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
   64
   Calgary, Alta.Michael A. Bardell
   CFO & Corporate Secretary
   56
   Vancouver, B.C.James R. Britton
   Vice President, Exploration
   68
   Vancouver, B.C.Wayne BabcockPresident and Chief Executive OfficerWayne Babcock, P. Geoph., holds a degree in Geophysics from the University of British Columbia and joinedAmoco 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, a Toronto-listed mining company.Mr. Babcock has been our President, Chief Executive Officer and a Director since 1979.Donald  Umbach Vice President and Chief Operating OfficerDonald 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 our Vice President and Chief Operating Officer.42John GreigDirectorJohn 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. He is the founder and member of the Board of Directors of publicly-traded exploration companies, including, Redcorp Ventures Ltd., and Eurozinc Mining Corp.  Mr. Greig is also a director and the Chairman of Cumberland Resources.Mr. Greig has been a director of us since July 1990.Jonathan Rubenstein DirectorBetween 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 has 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 Jennings DirectorDavid Jennings is a principal of the law firm Irwin, White & Jennings in Vancouver, Canada.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 us since August, 1999.43John LagadinDirectorMr. 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.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 us since August, 2000.Mike Bardell Chief Financial Officer and Corporate SecretaryMichael Bardell holds a diploma in finance and accounting and has over 30 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.Jim BrittonVice President, ExplorationJim 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.


44 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





The following table sets forth all annual and long-term compensation for services in all capacities to us for the last full fiscal year ended March 31, 2002 in respect of each of the individuals comprised of our Chief Executive Officer and our other four most highly compensated executive officers whose individual total compensation exceeded $100,000 and any individual who would have satisfied these criteria but for the fact he was not serving as an officer at the end of the last full fiscal year (collectively, the Named Executive Officers).  The information is presented in accordance with applicable Canadian regulations regarding reporting financial information on individual persons.


Named Executive OfficersName/Position
   Salary
   Bonus
   Other Annual Compensation(1)
   Options Granted(#)(2)
   Exercise Price
   Expiry DateWayne J. BabcockPresident & CEO
   112,008
   Nil
   318,841
   60,000
   $1.75
   28-Feb-2007Donald K. UmbachVice President & COO
   112,008
   Nil
   318,841
   60,000
   $1.75
   28-Feb-2007David G. Grohs, Manager, Engineering
   133,875
   Nil
   Nil
   20,000
   $1.75
   28-Feb-2007Michael A. Bardell,CFO & Corporate Secretary
   100,000
   33,500
   Nil
   40,000
   $1.75
   28-Feb-2007James R. BrittonVice-Pres., Exploration
   72,000
   Nil
   318,841
   30,000
   $1.75
   28-Feb-2007


(1)  The other annual compensation paid is in respect to payments to each of three Named Executive Officers pursuant to 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).


(2)We have a formalized stock option plan for the discretionary granting of incentive stock options to the Named Executive Officers.  The options indicated above were granted pursuant to that plan.











As of July 13, 1990, we had overriding royalty agreements with two of the Named Executive Officers and as of August 31, 1990, we had an overriding royalty agreement with a third Named Executive Officer.  Each of the overriding 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 two of the Named Executive Officers and June 1, 1987 for the third Named Executive Officer.


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 6 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


45





The following table sets forth all compensation for services in all capacities to us for the last full fiscal year ended March 31, 2002 in respect of each of the outside, independent directors.


Outside DirectorsName/Position
   Salary(1)
   Bonus
   Other Annual Compensation
   Options Granted(#)(2)
   Exercise Price
   Expiry DateJohn A. GreigDirector
   Nil
   Nil
   Nil
   17,500 15,000
   $2.15$2.10
   30-Apr-2011 23-Aug-2011Jonathan A. RubensteinDirector
   Nil
   Nil
   Nil
   17,500 15,000
   $2.15$2.10
   30-Apr-2011 23-Aug-2011John LagadinDirector
   Nil
   Nil
   Nil
   15,000
   $2.10
   23-Aug-2011David J. Jennings(3)Director
   Nil
   Nil
   Nil
   17,500 15,000
   $2.15$2.10
   30-Apr-2011 23-Aug-2011


(1)  During our last completed fiscal year, we did not pay any cash compensation to our directors (outside and inside), 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’ fiscal year 2002 legal fees amounted to $27,507.





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 July 31, 2002.


46Stock Options Outstanding as of July 31, 2002(Directors/Officers, as a group)Expiry Date
   Exercise Price
   Number of Shares of Common StockApril 22, 2003
   $1.72
   563,000January 24, 2005
   $1.45
   25,000September 29, 2005
   $2.10
   300,000August 17, 2010
   $1.72
   112,500September 29, 2010
   $2.10
   18,750April 30, 2011
   $2.15
   52,500August 23, 2011
   $2.10
   60,000February 28, 2007
   $1.75
   190,000April 20, 2012
   $1.65
   57,500Total
   
   1,379,250


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 July 31, 2002.  Stock Options Outstanding as of July 31, 2002(Non-Directors/Non-Officers) Expiry Date
   Exercise Price
   Number of Shares of Common StockApril 22, 2003
   $1.72
   177,000July 14, 2003
   $1.72
   40,000January 24, 2005
   $1.45
   20,000August 1, 2005
   $1.75
   30,000September 29,2005
   $2.10
   53,000March 1, 2006
   $2.17
   21,000April 1, 2006
   $1.70
   90,000April 15, 2006
   $2.25
   60,000February 28, 2007
   $1.75
   117,500Total
   
   608,500


47


The following table sets forth details of all grants of stock options during the most recently completed fiscal year to each of the Named Executive Officers.


Stock Options Granted to Named Executive OfficersName
   Number ofSecurities Under Options Granted
   % of Total Options Granted in Fiscal year
   Exercise Price (1)
   Expiration DateWayne J. Babcock
   60,000
   11
   $1.75
   Feb. 28, 2007Donald K. Umbach
   60,000
   11
   $1.75
   Feb. 28, 2007David G. Grohs
   20,000
   4
   $1.75
   Feb. 28, 2007Michael A. Bardell
   40,000
   7
   $1.75
   Feb. 28, 2007James R. Britton
   30,000
   5
   $1.75
   Feb. 28, 2007


(1)  The exercise price of options is based on the closing market price of our shares of common stock of the day preceeding the grant of such options.














Stock Options Exercised and Held by Named Executive OfficersNumber of
   Dollar Value ofUnexercised
   UnexercisedNumber of
   Aggregate
   Options/SAR’sAt Fiscal Year-End (3)
   In-the-Money Options/SAR’sAt Fiscal Year-End (3)(4)Name
   Securities Acquired On Exercise  (1)
   Dollar Value Realized  (2)
   Exercisable/Unexercisable
   Exercisable/UnexercisableWayne J. Babcock
   82,600
   156,002
   305,000/60,000
   47,150/12,000Donald K. Umbach
   102,500
   205,375
   260,000/60,000
   36,800/12,000David G. Grohs
   Nil
   Nil
   Nil/110,000
   Nil/26,500Michael A. Bardell
   106,000
   237,350
   135,000/40,000
   19,550/8,000James R. Britton
   31,500
   58,275
   135,000/30,000
   19,550/6,000


(1) Number of shares of common stock acquired on the exercise of stock options.


(2) Calculated using the average of the high and low prices for a round lot of our shares of common stock on the Toronto Stock Exchange on the day of exercise. (3) No SARs have been granted, therefore, the numbers relate solely to stock options. (4) Value of unexercised in-the-money options calculated using the closing price of our shares of common stock on the Toronto Stock Exchange on March 31, 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 the last fiscal year ended March 31, 2001, we had a total of six directors, two of which had one year remaining, two had two years remaining and two had three years remaining.





48       Name
   Term of Office Remaining
   Held Office SinceDirectors:Wayne J. Babcock
   Three year
   1980Donald K. Umbach
   Three year
   1986John A. Greig
   Two years
   1991Jonathan A. Rubenstein
   Two years
   1991David J. Jennings
   One year
   1999John Lagadin
   One year
   2000


Audit and Reserves Committee, Compensation Committee and Corporate Governance Committee


The following table sets forth details relating our Audit and Reserves Committee, Compensation Committee and Corporate Governance Committee for the last full fiscal year ended March 31, 2002.


Name
   CommitteeDirectors:John A. Greig
   Audit and Reserves Chair, Compensation, Corporate GovernanceJonathan A. Rubenstein
   Compensation Chair, Audit and Reserves, Corporate GovernanceDavid J. Jennings
   Corporate Governance Chair, Audit and Reserves, CompensationJohn Lagadin
   Audit and Reserves


The Audit and Reserves Committee is mandated to (i) assist the Board of Directors in fulfilling its fiduciary responsibilities relating to accounting and reporting practices and internal controls, (ii) review audited financial statements and management’s discussion and analysis of operations with the auditors, (iii) review the annual report and all interim reports of the auditors, (iv) ensure that no restrictions are placed by management on the scope of the auditor's review and examination of our accounts, (v) review the annual estimated reserves determined by independent engineers, (vi) recommend to the Board of Directors the firm of independent engineers to be appointed by the Board of Directors to evaluate our annual reserves and (vii) 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 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 twice during the fiscal year ended March 31, 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 has not set aside or accrued for pensions.  However, the shareholders previously approved royalty agreements with 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 since June 1, 1986 (two Named Executive Officers) and since June 1, 1987 (the third Named Executive Officer). During the past year, members of the Compensation


49 Committee recommended, and the Board of Directors approved, the granting of 307,500 options to our directors, officers and employees.  There were no option repricings during the year. Also, on October 23, 2001, the Compensation Committee resolved to increase the salary level of one executive position by a percentage of 39% over base salary.  No subsequent increases have been made to salary levels.


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, and the Vice President, Exploration.  After giving effect to these adjustments, the salary of these three 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 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 six directors.      None of the members of the Audit and Reserves, Compensation and Corporate Governance Committees has any indebtedness to us nor does any have any material interest, or have any associates or affiliates which have any material interest, direct or indirect, in any actual or proposed transaction in the last fiscal year which has materially affected or would materially affect us.


Employees





As of March 31, 2002, we employed thirteen 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, and nine 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 July 31, 2002, 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 OfficersName
   Position
   Number of Shares of Common Stock
   Percent of ClassWayne J. Babcock
   President & CEO, Director
   634,893
   3.1Donald K. Umbach
   Vice President & COO, Director
   257,016
   1.3John A. Greig
   Director
   140,077
   0.7Jonathan A. Rubenstein
   Director
   31,063
   0.2David J. Jennings
   Director
   20,000
   0.1John Lagadin
   Director
   Nil
   -Michael A. Bardell
   CFO & Corporate Secretary
   136,374
   0.7James R. Britton
   Vice President, Exploration
   110,500
   0.5


50


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 carrying 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 which 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





We announced the following significant events subsequent to March 31, 2002:


·Pursuant to a normal course issuer bid commencing May 1, 2002 and terminating March 31, 2003 or earlier, we were authorized to repurchase and cancel up to 1,000,000 shares of our common stock on the open market through the facilities of the Toronto Stock Exchange and The NASDAQ SmallCap Market.  As at August 5, 2002 we did not yet repurchase and cancel any shares of common stock pursuant to this bid.·On June 10, 2002, we announced our Farmout and Option Agreement (the Farmout Agreement) in the Orion area of northeastern British Columbia.  Under the terms of the Farmout Agreement, the farmee will have the right to earn a sliding scale interest in three designated blocks of our Orion acreage, comprising 28,334 gross acres (21,665 net) by drilling up to four horizontal test wells into the Upper Devonian Age, Jean Marie formation.  The first well, a commitment well, must be drilled by September 30, 2002.  To continue earning under the Farmout Agreement, the farmee has sixty days from rig release date of the first well to commit to drill the first of three option wells.  The first option well must be drilled by April 15, 2003.  The second and third option wells must be drilled by April 15, 2004.  Upon completion of the terms of the Farmout Agreement, we will retain an interest in the three blocks ranging from 20% to 50%, with a net weighted average working interest of approximately 32%.  We continue to hold a total of 1,669 gross acres (1,669 net) in the Orion area that is not subject to the Farmout Agreement.·On July 30, 2002, we announced our Participation and Farmin Agreement (the Farmin Agreement) in the Cypress area of northeast British Columbia.  Under the terms of the Farmin Agreement, we will have the right to earn a net weighted average working interest of 35% in two out of eight land blocks comprising approximately 5,120 acres, by paying 50% of the cost to drill two test wells.  The first well, a commitment well and the second an option well, are expected to cost us $1.3 million and $0.9 million, respectively.  Upon completion of the terms of the Farmin Agreement, we will have the right to earn a 50% working interest in the two test-well land blocks, subject to a convertible 15% gross overriding royalty, and a 30% working interest in the remaining six land blocks.51Item 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.














VSE/TSX (in Cdn $)
   NASDAQ SmallCap  (in U.S. $)Year
   High
   Low
   High
   Low2002
   2.63
   1.55
   1.75
   0.922001
   3.00
   1.55
   2.06
   1.002000
   2.05
   1.44
   1.50
   0.971999
   1.90
   1.40
   1.38
   0.881998
   2.64
   1.30
   1.94
   0.88
 Prices of Common Stock
   TSX (Cdn $)
   (NASDAQ Small Cap (U.S. $)2001-2002
   High
   Low
   High
   LowQ1 ended June 30, 2001
   2.52
   1.69
   1.75
   1.06Q2 ended September 30, 2001
   2.35
   1.55
   1.55
   0.92Q3 ended December 31, 2001
   2.05
   1.56
   1.31
   1.02Q4 ended March 31, 2002
   2.05
   1.60
   1.34
   1.002000-2001Q1 ended June 30, 2000
   2.10
   1.55
   1.34
   1.00Q2 ended September 30, 2000
   2.21
   1.65
   1.50
   1.44Q3 ended December 31, 2000
   3.00
   2.20
   2.03
   1.75Q4 ended March 31, 2001
   2.75
   1.88
   2.06
   1.09  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
   LowJul/2002
   1.80
   1.60
   1.15
   1.07Jun//2002
   2.00
   1.60
   1.25
   1.09May/2002
   1.78
   1.60
   1.17
   1.03Apr/2002
   1.88
   1.65
   1.19
   1.01Mar/2002
   2.05
   1.65
   1.34
   1.02Feb/2002
   1.77
   1.60
   1.10
   1.00
 52
 Item 10.    Additional Information
 
 Memorandum and Articles of Association
 Our objects and purposes as set forth in our Memorandum and Articles
 
 
 Matters relating to our Directors
 
 Director’s power to vote on a proposal, arrangement or contract in which the director is materially interested
 
 
 Director’s power, in the absence of an independent quorum, to vote compensation to themselves or any members of their body
 
 
 Borrowing powers exercisable by the directors and how such borrowing powers can be varied
 
 
 
 Retirement or non-retirement of directors under an age limit requirement
 
 Number of shares, if any required for director’s qualification
 
 
 53 Rights, preferences and restrictions attaching to each class of shares
 
 Dividend rights, including time limit after which dividend entitlement lapses
 
 Voting rights
 
 Rights to share in surplus in event of liquidation
 
 Redemption
 
 Other
 
 
 Actions necessary to change the rights of holders of our stock
 
 
 Conditions governing manner in which annual general meetings and extraordinary general meetings of shareholders are convoked
 
 Annual Meeting
 
 Special Meeting
 
 54
 
 Limitations on rights to own securities of the Company
 
 
 
 
 
 (a)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; (b)governments of WTO members; and (c)entities that are not Canadian controlled, but which are WTO investor controlled, as determined by rules specified in the ICA.
 
 
 
 55
 
 
 
 
 (a)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; (b)the effect of the investment on exports from Canada; (c)the degree and significance of participation by Canadians in the Canadian business and in any industry in Canada of which it forms a part; (d)the effect of the investment on productivity, industrial efficiency, technological development, product innovation and product variety in Canada; (e)the effect of the investment on competition within any industry or industries in Canada; (f)the compatibility of the investment with national industrial, economical and cultural policies; (g)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 (h)the contribution of the investment to Canada’s ability to compete in world markets.
 
 56
 
 
 
 
 
 
 
 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
 
 
 
 Provisions of our Memorandum or Articles governing the ownership threshold above which shareholder ownership must be disclosed
 
 
 Significant differences between law applicable to us and law of the United States with respect to the matters addressed above in this Item 10
 
 
 
 
 
 57 Material Contracts and Agreements
 
 We have entered into the following ten agreements in the two-year period immediately preceding this report.  Any other contracts/agreements that we have entered into during the same period 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
 Contribution, Mutual Interest and Exclusion 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.
 
 GasEDI Base Contract for Short-Term Sale and Purchase of Natural Gas
 
 Exchange Controls
 
 
 58
 
 
 
 
 
 
 
 
 
 
 
 
 The following investments by a nonare subject to review by Investment Canada:


























59


Impact of the North American Free Trade Agreement















































Taxation

















60


Canadian Federal Income Tax Considerations

















United States Federal Income Tax Considerations
































61


Financing Exploration and Development Drilling Through Canadian Income Tax Incentives














During fiscals 2002, 2001 and 2000 we did not raise any flowfunding.





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.





Commodity Price Risks and Credit Risk





As an independent oil and gas producer, our gross revenues, funds flow from operations, earnings, reserve values, access to capital and future rate-of-growth are substantially dependent upon the prevailing prices of natural gas, natural gas liquids and crude oil.  Prevailing prices for such commodities can be subject to wide fluctuations in response to relatively minor changes in supply and demand, and a variety of additional factors beyond our control.


62 Prices for natural gas and certain other by-products associated with natural gas are influenced solely by the forces of the North American marketplace, whereas the prices for condensate and oil are influenced by the forces of the world marketplace.  Historically, prices received for all commodities produced by us have been volatile and unpredictable, and such volatility is expected to continue.





We use a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of natural gas and natural gas liquids (representing 96% of fiscal 2002’s gross revenues) may have on the fair value our gross revenues.  The following table demonstrates the effects of declines in the weight-averaged prices of our main revenue-generating commodities (see also Sensitivity Analysis under Item 5. in this report).





Weighted Average Prices and the Effect of Adversity Weight-Averaged Prices Achieved
   Fiscal 2002 Weighted Average PricesAfter Consideration of Adversity %Commodity Type
   Q4, Fiscal 2002
   Fiscal 2002
   10%
   20%
   30%Natural gas ($/mcf)
   $3.42
   $3.81
   $3.43
   $3.05
   $2.67Natural gas liquids $/bbl)
   $14.99
   $19.30
   $17.37
   $15.44
   $13.51


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


Impact on Gross Revenues (in $000’s) After Consideration of Pricing Adversity Commodity Type
   Q4, 2002
   Fiscal 2002
   10%
   20%
   30%Natural gas
   5,076
   20,944
   18,850
   16,755
   14,661Natural gas liquids
   1,132
   4,442
   3,998
   3,554
   3,109


We have not undertaken any transactions of a hedging nature in an effort to achieve more predictable cash flows and earnings from the sale of any portion of its gas, liquids or oil production.  We undertake a periodic review to decide how hedging some of its natural gas might affect its overall contract mix.  Hedging may assist in limiting the downside risk of adverse price movements, however, it may also limit future revenues from favorable price movements.





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 has no obligation to deliver or receive quantities of natural gas, liquids or oil pursuant to a swap.





In fiscal 2002, the majority of our total natural gas sales were split evenly between two customers and our total natural gas liquids between three different 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 natural gas and natural gas liquids.





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.  For example, approximately 45% of our year 2002 balance of accounts receivable is due from four  customers, subject to normal credit risk.  Further, while our largest producing properties during fiscal 2002 were self-operated, six out of thirteen 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 nonby any counterparty.





ProGas, a Calgary based natural gas marketing company, is a ‘netback aggregator’ owned 100% by BP Amoco.  ProGas has a broad, long-term, contracted natural gas reserve supply of over 3.5 trillion cubic feet, dedicated by us and over 170 other contributing producers, thereby helping us to mitigate potential financial penalties by giving greater flexibility to ProGas to contract without requiring supply warranties.  We have contracted 50% of our 75% working interest in St. Albert natural gas to ProGas pursuant to a ‘life-of-reserves’ agreement.





The netback price paid by ProGas to us and other contributing gas producers is determined monthly by deducting transportation and operating costs from the pooled sales revenue.  ProGas does not charge a marketing fee, but recovers its cost of doing business through a fixed monthly amount as approved by its producers.





ProGas maintains a diverse portfolio of spot (one month or less), short-term (less than one year) and long(one year and greater) sales contracts, diverse both in terms of geographic distribution and by type of market served (local distribution   63 systems, cogen, industrial or pipeline).  Risk exposure is minimized through the use of a variety of pricing mechanisms and other terms to ensure the overall market portfolio covers a wide range of scenarios.





In order to maximize the netback price while at the same time limit price volatility that is generally associated with spot pricing, ProGas purchases gas from us on the basis of a conglomerate of market prices.  As an example, in March, 2002, of the total gas purchased by ProGas from us, approximately 27% was based on spot pricing, 1% on short-term pricing and 25% on long-term pricing.  Further, in March 2002, ProGas utilized 17 individual price drivers with 16 unique delivery points to establish price matrices.  Examples of price drivers used: AECO (Alberta Energy Company), NYMEX (New York Mercantile Exchange), Chicago, Louisiana/Oklahoma and Michigan.





If we desire to pursue hedging transactions, ProGas, in conjunction with a third party provider, offers hedging services.





Interest Rate Risks





We are exposed to interest rate risk relating to existing debt pursuant to a revolving credit facility.  We do not engage in interest rate swaps to hedge the interest rate exposure associated with the credit agreement.  If market interest rates for shortborrowings increase by 1%, the increase in our interest expense would be immaterial (see Sensitivity Analysis under Item 5 in this report).





We are party to a gas facility processing lease agreement requiring minimum annual lease payments until Year 2003.  Under the terms of this agreement, the interest rate element is fixed, thereby eliminating interest rate risk concerns relative to the lease payments.





Item 12.    Description of Securities Other than Equity Securities





Not applicable.


64Part 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














Item 15.    [Reserved] ......................n/aItem 16.    [Reserved] ......................n/a


Part III.


Item 17.    Financial Statements


|Auditors’ Report                                                                       | F-1
|-------------------------------------------------------------------------------------- | ---
|Balance Sheets as of March 31, 2002 and March 31, 2001                                 | F-2
|Statements of Operations and Deficit for the years ended March 31, 2002, 2001 and 2000 | F-3
|Statements of Cash Flows for the years ended March 31, 2002, 2001 and 2000             | F-4
|Notes to Financial Statements                                                          | F-5




Item 18.    Financial Statements


(a)  See Item 17.(b)  n/a





Item 19.    Exhibits


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


65Financial Statements 
 Dynamic Oil & Gas, Inc.
 March 31, 2002 and 2001
 CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS
 We consent to the use of our report dated June 14, 2002 with respect to the financial statements of Dynamic Oil Limited included in its Annual Report (Form 20-F) for the year ended March 31, 2002.
 
 Vancouver, Canada,
   /s/ ERNST & YOUNG LLPAugust 16, 2002.
   Chartered Accountants             Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  2000
 
 AUDITORS’ REPORT
 
 Dynamic Oil & Gas, Inc.
 Dynamic Oil & Gas, Inc.
 
 
 
 
 Vancouver, Canada,
   /s/ ERNST & YOUNG LLPJune 14, 2002.
   Chartered Accountants F-1      Dynamic Oil & Gas, Inc.
 Incorporated under the laws of British Columbia
 BALANCE SHEETS
 (in Canadian dollars)
 
 As at March 31 2002
   2001$
   $ASSETS[note 3]CurrentCash and cash equivalents
   
   3,493,448Accounts receivable [note 9]
   5,979,532
   4,444,834Prepaid expenses
   365,227
   240,466Total current assets
   6,344,759
   8,178,748Future income tax asset [note 6]
   279,000
   Natural gas and oil interests [note 2]
   30,365,636
   21,678,527Capital assets [note 2]
   162,499
   133,38037,151,894
   29,990,655LIABILITIES AND SHAREHOLDERS’ EQUITYCurrentBank indebtedness
   842,812
   Operating loan [note 3]
   14,750,000
   Accounts payable and accrued liabilities
   3,611,314
   5,664,739Income taxes payable [note 6]
   421,360
   545,144Total current liabilities
   19,625,486
   6,209,883Deferred gain on sale [note 4]
   109,327
   339,601Provision for future removal and site restoration
   824,098
   539,730Future income tax liability [note 6]
   
   2,955,000Total liabilities
   20,558,911
   10,044,214Share capital [note 5]
   20,914,522
   20,641,720Deficit
   (4,321,539)
   (695,279)Total shareholders’ equity
   16,592,983
   19,946,44137,151,894
   29,990,655 Commitments [note 12]
 See accompanying notes and schedules On behalf of the Board:  Director/s/Wayne J. Babcock
   Director/s/Donald K. Umbach
 F-2Dynamic Oil & Gas, Inc.
 
 STATEMENTS OF OPERATIONS AND DEFICIT
 (in Canadian dollars)
 
 Years ended March 31 2002
   2001
   2000$
   $
   $REVENUENatural gas, liquids and oil sales
   26,401,872
   34,462,676
   15,770,327Royalties [note 10]
   (6,500,447)
   (9,857,954)
   (4,634,996)Production costs
   (5,845,958)
   (4,579,845)
   (3,690,464)14,055,467
   20,024,877
   7,444,867Alberta royalty tax credit
   159,274
   498,773
   (7,134)14,214,741
   20,523,650
   7,437,733EXPENSESGeneral and administrative [schedule 1]
   2,347,212
   1,569,175
   1,618,821Interest expense on operating loan
   494,685
   240,420
   194,487Interest income
   (22,066)
   (25,601)
   (9,583)2,819,831
   1,783,994
   1,803,725Earnings from operations beforethe following:
   11,394,910
   18,739,656
   5,634,008Amortization and depletion [schedule 2]
   12,172,943
   3,006,964
   1,464,155Exploration expenses [schedule 3]
   4,646,018
   1,923,194
   1,299,276Gain on sale of natural gas and oil interests
   (4,566)
   (639,532)
   (Loss) earnings before taxes
   (5,419,485)
   14,449,030
   2,870,577Current income tax expense [note 6]
   57,600
   572,000
   Future income tax (recovery) expense [note 6]
   (1,958,000)
   4,163,000
   (1,208,000)Net (loss) earnings
   (3,519,085)
   9,714,030
   4,078,577Deficit, beginning of year
   (695,279)
   (10,379,392)
   (13,943,643)Premium on purchase and cancellation ofcommon shares [note 5[e]]
   (107,175)
   (29,917)
   (510,094)Share issue costs
   
   
   (4,232)Deficit, end of year
   (4,321,539)
   (695,279)
   (10,379,392)Earnings per share [note 7]basic
   (0.17)
   0.49
   0.21diluted
   (0.17)
   0.48
   0.20 See accompanying notes and schedules
 F-3Dynamic Oil & Gas, Inc.
 
 STATEMENTS OF CASH FLOWS
 (in Canadian dollars)
 
 Years ended March 31 2002
   2001
   2000$
   $
   $OPERATING ACTIVITIES(Loss) earnings
   (3,519,085)
   9,714,030
   4,078,577Add (deduct) items not involving cash:Amortization and depletion
   12,172,943
   3,006,964
   1,464,155Future income taxes
   (1,958,000)
   4,163,000
   (1,208,000)Exploration expenses
   4,646,018
   1,923,194
   1,299,276Gain on sale of natural gas and oil interests
   (4,566)
   (639,532)
   Funds flow from operations
   11,337,310
   18,167,656
   5,634,008Changes in non-cash working capital affectingoperating activities [note 8[a]]
   (1,558,807)
   1,096,162
   (963,834)Cash provided by operating activities
   9,778,503
   19,263,818
   4,670,174FINANCING ACTIVITIESBank indebtedness
   842,812
   
   Operating loan
   14,750,000
   (6,000,000)
   3,750,000Shares issued for cash
   455,420
   200,000
   121,000Share repurchases
   (289,793)
   (89,689)
   (1,376,723)Share issue costs
   
   
   (4,232)Cash provided by (used in) financing activities
   15,758,439
   (5,889,689)
   2,490,045INVESTING ACTIVITIESPurchase of capital assets
   (116,180)
   (78,749)
   (100,113)Natural gas and oil interests
   (21,994,897)
   (11,502,902)
   (5,626,771)Exploration expenses
   (4,646,018)
   (1,923,194)
   (1,299,276)Proceeds on sale of natural gas and oil interests
   4,566
   1,072,395
   Changes in non-cash working capital affectinginvesting activities [note 8[b]]
   (2,277,861)
   1,109,888
   824,512Cash used in financing activities
   (29,030,390)
   (11,322,562)
   (6,201,648)(Decrease) increase in cash and cash equivalents
   (3,493,448)
   2,051,567
   958,571Cash and cash equivalents, beginning of year
   3,493,448
   1,441,881
   483,310Cash and cash equivalents, end of year
   
   3,493,448
   1,441,881 Supplemental disclosures of cash flow informationCash paid during the year for:Interest
   589,549
   259,230
   213,109Income taxes
   1,167,720
   26,856
   Funds flow from operations per share[note 7]- basic
   0.55
   0.91
   0.29- diluted
   0.55
   0.89
   0.28See accompanying notes and schedules
 F-4    Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  2000
 
 
 
 
 
 
 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
 
 
 
 Accounting principles
 
 
 
 Use of estimates
 
 
 
 Natural gas and oil interests
 
 
 
 
 
 
 
 F-5Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20001. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)
 
 Cash and cash equivalents
 Cash and cash equivalents are recorded at cost, which approximates current market value.
 
 
 Joint interests
 
 
 
 Future removal and site restoration
 
 
 
 Capital assets
 
 
 Furniture, fixtures and equipment
   - 10% per annumComputer equipment
   - 33.3% per annum
 Income taxes
 
 
 
 F-6Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20001. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)
 
 Stock-based compensation plan
 
 
 
 Foreign currency translation
 
 
 
 Measurement uncertainty
 
 
 
 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 is amortized to income over the lease back term.
 F-7Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20001. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont’d.)
 
 Earnings per share
 
 
 
 Operating loan
 
 
 
 2. NATURAL GAS AND OIL INTERESTS, AND CAPITAL ASSETS
 Accumulatedamortization and
   Net bookCost
   depletion
   value$
   $
   $2002Natural gas and oil interests
   49,453,746
   19,088,110
   30,365,636Furniture, fixtures and computer equipment
   453,733
   291,234
   162,4992001Natural gas and oil interests
   29,536,063
   7,857,536
   21,678,527Furniture, fixtures and computer equipment
   337,554
   204,174
   133,380
 F-8Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20002.    NATURAL GAS AND OIL INTERESTS, AND CAPITAL ASSETS (cont’d.)
 
 
 
 Acquisition of Additional St. Albert oil and gas interest
 
 
 Previous
   NewDescription of assets
   interest
   interestProducing gas wells - 19
   50%
   75%Producing oil wells - 7
   25%
   75%Oil battery - 1
   25%
   75%Solution gas plant - 1
   
   25%Sales gas pipeline complete with facilities - 1
   
   25%
 
 Dynamic’s share of the purchase price paid for these new assets was $14,739,471.
 F-9Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20003. OPERATING LOAN
 
 
 
 4. ST. ALBERT SALE AND LEASEBACK
 
 
 
 5. SHARE CAPITAL
 Authorized 60,000,000 common shares without par value.
 2002
   2001
   2000#
   $
   #
   $
   #
   $Outstanding, beginningof year
   20,145,930
   20,641,720
   19,848,256
   20,419,742
   20,388,732
   21,079,371Shares issued for cash:Stock options exercised
   495,100
   455,420
   279,000
   200,000
   222,500
   121,000Issued on conversion ofcollateralized convertibledebt [note 5[d]]
   
   
   76,774
   81,750
   76,224
   86,000Share repurchases andcancellations
   (178,800)
   (182,618)
   (58,100)
   (59,772)
   (839,200)
   (866,629)Outstanding, end of year
   20,462,230
   20,914,522
   20,145,930
   20,641,720
   19,848,256
   20,419,742
 F-10Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20005. SHARE CAPITAL (cont’d.)
 
 
 
 
 
 
 
 
 2002
   2001
   2000Number
   Weighted
   Number
   Weighted
   Number
   Weightedof
   average
   of
   average
   of
   averageshares
   option price
   shares
   option price
   shares
   option price#
   $
   #
   $
   #
   $Outstanding at beginning of year
   1,855,350
   1.29
   1,599,100
   1.29
   1,776,600
   1.19Granted
   570,000
   1.87
   535,250
   2.00
   45,000
   1.45Exercised
   (495,100)
   0.92
   (279,000)
   0.72
   (222,500)
   0.54Outstanding at end of year
   1,930,250
   1.83
   1,855,350
   1.29
   1,599,100
   1.29Options exercisable at year end
   1,458,750
   1.84
   1,855,350
   1.29
   1,599,100
   1.29
 F-11Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20005. SHARE CAPITAL (cont’d.)
 [c]    The Company has options outstanding and exercisable as follows:Exercise priceNumber
   $
   Expiry date740,000
   1.72
   April 22, 200340,000
   1.72
   July 14, 200345,000
   1.45
   January 24, 200530,000
   1.75
   August 1, 2005353,000
   2.10
   September 29, 2005112,500
   1.72
   August 17, 201018,750
   2.10
   September 29, 20107,000
   2.17
   March 1, 200652,500
   2.15
   April 30, 201160,000
   2.10
   August 23, 20111,458,750
   1.84These options have a weighted average remaining contractual life of 3.06 years.
 
 Shares issued
   Weighted
   Original principalYears of
   upon conversion
   average price
   amounts convertedconversion
   #
   $
   $2001
   76,774
   1.06
   81,7502000
   76,224
   1.13
   86,0001997-1999
   1,152,557
   0.72
   832,250Total
   1,305,555
   0.77
   1,000,000
 F-12Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20005. SHARE CAPITAL (cont’d.)
 
 
 Normal course issuer bid date of
   Share repurchases/Commencement
   Termination
   cancellations authorized9-Apr-01
   31-Mar-02
   1,000,0001-Oct-99
   30-Sep-00
   1,000,00017-Aug-98
   16-Aug-99
   980,680 Under these normal course issuer bids, the Company purchased and recorded the following:2002
   2001
   2000#
   $
   #
   $
   #
   $Bid termination date: 31-Mar-02
   (178,800)
   (289,793)
   
   
   
   Bid termination date: 30-Sep-00
   
   
   (58,100)
   (89,689)
   (372,900)
   (571,607)Bid termination date: 16-Aug-99
   
   
   
   
   (466,300)
   (805,116)(178,800)
   (289,793)
   (58,100)
   (89,689)
   (839,200)
   (1,376,723)Average purchase price
   $1.62
   
   $1.54
   
   $1.64Recorded as an increase of deficit
   
   107,175
   
   29,917
   
   510,094Recorded as a reduction of share capital
   
   (182,618)
   
   (59,772)
   
   (866,629)
 F-13Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20006. INCOME TAXES
 
 2002
   2001$
   $Long term future tax assets (liabilities):CCA in excess of book depreciation
   (46,000)
   (3,289,000)Finance charges
   2,000
   8,000Deferred gain recognized for tax purposes
   46,000
   126,000Provision for future removal and site restoration costs
   277,000
   200,000Net future tax assets (liabilities)
   279,000
   (2,955,000) Significant components of the provision for income taxes attributable to continuing operations are as follows:Liability method2002
   2001
   2000$
   $
   $Current tax expense
   57,600
   572,000
   Future income tax benefit resulting fromrecognition of loss carryforwards
   
   
   (144,000)Future income tax benefit resulting fromrecognition of attributed royalty incomecarryforwards
   
   
   (98,000)Future income tax expense (benefit) relating toorigination and reversal of temporarydifferences
   (2,666,800)
   4,740,000
   (966,000)Effect of changes in tax rates
   708,800
   (577,000)
   Income tax (recovery) expense
   (1,900,400)
   4,735,000
   (1,208,000)
 F-14Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20006. INCOME TAXES (cont’d.)
 
 
 Liability method2002
   2001
   2000$
   %
   $
   %
   $
   %Tax at combined federaland provincial rates
   (2,371,000)
   43.75
   6,483,000
   44.87
   1,295,000
   45.12Tax effect of non-deductiblecrown royalties
   1,068,000
   
   1,329,000
   
   701,000Tax effect of income nottaxable
   (64,900)
   
   (224,000)
   
   3,000Amortization of deferredgain previously recognizedfor tax purposes
   
   
   
   
   (156,000)Tax effect of origination andreversal of temporary differences
   
   
   
   
   389,000Tax effect of resource allowance
   (1,290,300)
   
   (2,295,000)
   
   (736,000)Utilization of non-capital lossesnot previously recognized foraccounting purposes
   
   
   
   
   (1,496,000)Recognition of loss carryforwardsstill available
   
   
   
   
   (144,000)Recognition of attributed royaltyincome carryforwards still available
   
   
   0051
   
   (98,000)Large Corporation Tax in excess ofsurtax
   49,000
   
   19,000
   
   Recognition of benefit oftemporary differences
   
   
   
   
   (966,000)Effect of changes in tax rates
   708,800
   
   (577,000)
   
   (1,900,400)
   
   4,735,000
   
   (1,208,000)
 F-15Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20007. EARNINGS PER SHARE AND FUNDS FLOW FROM OPERATIONS
 
 
 2002
   2001
   2000$
   $
   $NumeratorNet (loss) earnings for the year
   (3,519,085)
   9,714,030
   4,078,577DenominatorWeighted average number of commonshares outstanding
   20,365,031
   19,937,585
   19,709,904Effect of dilutive stock options
   101,512
   507,934
   464,58120,466,543
   20,444,979
   20,174,485Basic (loss) earnings per share
   (0.17)
   0.49
   0.21Diluted (loss) earnings per share
   (0.17)
   0.48
   0.20
 
 
 8. CHANGES IN NON-CASH WORKING CAPITAL BALANCES
 
 2002
   2001
   2000$
   $
   $Accounts receivable
   (581,264)
   (2,463,146)
   (352,708)Prepaid expenses
   (124,761)
   (122,782)
   (23,928)Accounts payable and accrued liabilities
   (728,998)
   3,136,946
   (587,198)Income taxes payable
   (123,784)
   545,144
   (1,558,807)
   1,096,162
   (963,834) F-16Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  20008. CHANGES IN NON-CASH WORKING CAPITAL BALANCES (cont’d.)
 [b]    Changes affecting investing activities comprise:2002
   2001
   2000$
   $
   $Accounts receivable
   (953,434)
   217,404
   302,402Accounts payable
   (1,324,427)
   892,484
   522,110(2,277,861)
   1,109,888
   824,512
 9. FINANCIAL INSTRUMENTS
 
 
 
 
 
 10. OVERRIDING ROYALTY
 
 
 
 F-17Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  200011.    RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
 
 
 Consolidated net (loss) earnings under U.S. GAAP would be:  2002
   2001
   2000For the years ended March 31
   $
   $
   $Net (loss) earnings under Canadian GAAP
   (3,519,085)
   9,714,030
   4,078,577AdjustmentsOptions issued for services [a]
   
   (20,100)
   Ceiling test adjustment to natural gasproperties [b]
   (216,100)
   
   (145,050)Income taxes [c]
   669,100
   (577,000)
   Net (loss) earnings and comprehensive(loss) earnings under U.S. GAAP
   (3,066,085)
   9,116,930
   3,933,527Common shares - weighted average
   20,365,031
   19,937,585
   19,709,904Net (loss) earnings per common share underU.S. GAAP- basic
   (0.15)
   0.46
   0.20- diluted
   (0.15)
   0.45
   0.19 After adjusting for certain differences, selected consolidated balance sheet items under U.S. GAAP would be:2002
   2001Canadian
   U.S.
   Canadian
   U.S.basis
   basis
   basis
   basis$
   $
   $
   $Future income tax asset [c]
   279,000
   371,100
   
   Future income tax liability [c]
   
   
   2,955,000
   3,532,000Natural gas and oil interests [b]
   30,365,636
   30,149,536
   21,678,527
   21,678,527Share capital [a, d]
   20,914,522
   21,882,682
   20,641,720
   21,609,880Deficit [a, b, c, d]
   (4,321,539)
   (5,421,657)
   (695,279)
   (2,355,572)
 F-18Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  200011.    RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)
 
 Stock-based compensation
 
 Under Canadian GAAP, no compensation expense is recognized when stock options are issued to directors, employees or consultants. Under U.S. GAAP, the Company accounts 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. The Company uses the Black-Scholes option pricing model to determine the fair value of stock options granted to consultants. While the Company follows APB 25 for employees and directors, it does comply with the disclosure provisions of SFAS 123.
 
 
 
 During 2002, the Company’s option grants included 20,000 stock options issued to a consultant for services at $1.75 per option, resulting in administrative expense recorded in the U.S. GAAP financial statements of $nil in accordance with SFAS 123. These options vest over three years in increments of 6,667 per year beginning February 28, 2003 and expiring on February 28, 2007. At the time of the grant, the fair value of the options was $14,800, an amount that will be recognized as compensation expense evenly over the next three years as the options vest.
 
 During 2002, the Company’s option grants consisted of 550,000 options issued to employees and directors with exercise prices equal to the fair value of the Company’s stock and, in accordance with APB 25 no compensation expense was required to be recorded.
 
 
 
 
 F-19Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  200011.    RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)
 Prior to 2000, there had been $1,519,021 of compensatory stock options issued in accordance with APB 25.
 
 2002
   2001
   2000$
   $
   $Net (loss) earnings, U.S. basis as reported
   (3,066,085)
   9,116,930
   3,933,527Pro forma net (loss) earnings, U.S. basisunder SFAS 123
   (3,229,062)
   8,716,719
   3,875,027(Loss) earnings per share, U.S. basis as reported
   (0.15)
   0.46
   0.20(Loss) earnings per share, U.S. basisunder SFAS 123
   (0.16)
   0.44
   0.20
 
 2002
   2001
   2000$
   $
   $Dividend yield
   0%
   0%
   0%Expected volatility
   57%
   48%
   88%Risk-free interest rate
   5%
   6%
   5%Expected lives
   3 years
   3 years
   3 years
 F-20Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  200011.    RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (cont’d.)
 
 
 
 
 
 
 
 
 
 12. COMMITMENTS
 
 
 Lease costs pursuant to the leaseback agreement are recorded as production costs.
 
 
 F-21Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  200012. COMMITMENTS (cont’d.)
 
 Gasprocessing
   Officefacilities
   premises$
   $2003
   467,811
   72,3292004
   
   60,274467,811
   132,603
 13. ECONOMIC DEPENDENCY
 
 
 
 
 
 
 Both agreements include an automatic renewal for a further ten years, subject to fee re-negotiation.
 F-22Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  200014. SUBSEQUENT EVENTS
 
 Normal course issuer bid
 
 
 
 15. COMPARATIVE FIGURES
 Certain comparative figures have been reclassified to conform with the current year’s presentation.
 F-23
 Dynamic Oil & Gas, Inc.
 
 Schedule 1
 GENERAL AND ADMINISTRATIVE
 (in Canadian dollars)
 
 Years ended March 31 2002
   2001
   2000$
   $
   $Advertising and promotion
   250,792
   218,880
   233,098Insurance
   122,583
   43,034
   40,967Interest
   98,087
   18,469
   16,551Office and printing
   432,947
   231,490
   219,330Professional fees
   530,203
   402,925
   351,673Provincial capital taxes
   83,062
   37,000
   Regulatory and other fees
   72,472
   70,219
   107,658Rent
   89,581
   84,646
   67,183Salaries and benefits (1)
   1,086,958
   633,601
   572,577Telephone
   16,423
   13,354
   18,406Travel
   23,054
   20,361
   17,167Cost recoveries
   (458,950)
   (204,804)
   (25,789)2,347,212
   1,569,175
   1,618,821 (1) The Company also pays overriding royalties to three officers as described in note 10.
 Schedule 2
 AMORTIZATION AND DEPLETION
 (in Canadian dollars)
 Years ended March 31 2002
   2001
   2000$
   $
   $Amortization and depletion
   12,118,849
   3,132,663
   1,644,209Future removal and site restoration provision
   284,368
   184,925
   166,205Amortization of deferred financing costs
   
   1,412
   6,122Amortization of deferred gain on sale
   (230,274)
   (312,036)
   (352,381)12,172,943
   3,006,964
   1,464,155
 F-24Dynamic  Oil  &  Gas,  Inc.NOTES  TO  FINANCIAL  STATEMENTS(in  Canadian  dollars)March  31,  2002,  2001  and  2000Dynamic Oil & Gas, Inc.
 
 Schedule 3
 EXPLORATION EXPENSES
 (in Canadian dollars)
 
 Years ended March 31 2002
   2001
   2000$
   $
   $Drilling
   3,821,374
   667,684
   948,372Seismic data activity
   649,216
   1,101,969
   184,997Non-producing lease rentals
   64,605
   51,856
   28,460Property investigations
   110,823
   101,685
   137,4474,646,018
   1,923,194
   1,299,276
   F-25    Signatures
 
 We hereby certify that we meet all of the requirements for filing on Form 20and that we have duly caused and authorized the undersigned to sign this Annual Report on our behalf.
 Date: August 19, 2002 Dynamic Oil & Gas, Inc.  By:  /s/ Michael A. BardellMichael A. Bardell
 Chief Financial Officer & Corporate Secretary
 
   66     INDEX TO EXHIBITS
 Exhibit Numbers
   EXHIBITS
   Sequentially Numbered Page1(i) and 2(a)(i)
   Certificate of Incorporation and Articles/By(1)1(i) and 2(a)(i)
   Certificate of Increase of Authorized Capital of the Company and Name Change.(3)1(i) and 2(a)(i)
   Corporate Governance Committee Guidelines2(a)(ii)
   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. (6)(xxvi)
   Overriding Royalty Agreement dated July 13, 1990 between Dynamic Oil Limited and Donzoil Ltd. (6)(xxvii)
   Overriding Royalty Agreement dated August 31, 1990 between Dynamic Oil Limited and James R. Britton. (6)(xxviii)
   GasEDI Base Contract for Short-Term Sale and Purchase of Natural Gas dated October 15, 2001 between Nexen Marketing and Dynamic Oil & Gas, Inc. (6)6
   Statement re: Earnings Per Share Calculation. (5)10.1
   Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (6)10.2
   Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (6) 
 Unless otherwise noted, each exhibit to this Annual 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 under Exhibit No 3.
 (2)    Form 20-F Annual Report filed on August 18, 1998 under Exhibit No. 3.
 (3)    Form 20-F Annual Report filed on September 9, 1999 under Exhibit No. 3.
 (4)    Form 20-F Annual Report filed on August 16, 2000 under Exhibit No. 3.
 (5)    Form 20-F Annual Report filed on August 15, 2001 under Exhibit No. 4.


(6)    Filed herewith.