UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

FORM 20-F

|   | REGISTRATION STATEMENT PURSUANT TO SECTION 12(b)
      OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934                                                             
|-- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------
|   |                                                                                                                                                                  
|OR
|   |                                                                                                                                                                  
|   | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
      EXCHANGE ACT OF 1934                                                                       
|   |                                                                                                                                                                  
|OR
|   |                                                                                                                                                                  
|   | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
      SECURITIES EXCHANGE ACT OF 1934 for the transition period April 1, 2002
      to December 31, 2002

Commission File Number 0-17551

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

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

205 - 10711 Cambie Road
  Richmond, British Columbia V6X 3G5, Canada(Address of principal executive offices)

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

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

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

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

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

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

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

1

---





TABLE OF CONTENTS



|                                                                                                                                                       |                                                                                                                                   | Page | 
|------------------------------------------------------------------------------------------------------------------------------------------------------ | --------------------------------------------------------------------------------------------------------------------------------- | ---- | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Glossary of Terms..................................................................................................................................... | 3                                                                                                                                 |     
|                                                                                                                                                       |                                                                                                                                   |      | 
|Part I.                                                                                                                                                |                                                                                                                                   |      | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 1.                                                                                                                                                | Identity of Directors, Senior Management and Advisers.........................................                                    | 6    | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 2.                                                                                                                                                | Offer Statistics and Expected Timetable...................................................................                        | 6    | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 3.                                                                                                                                                | Key Information..........................................................................................................         | 6    | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 4.                                                                                                                                                | Our Information..........................................................................................................         | 14   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 5.                                                                                                                                                | Operating and Financial Review and Prospects........................................................                              | 33   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 6.                                                                                                                                                | Directors, Senior Management and Employees.......................................................                                 | 46   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 7.                                                                                                                                                | Major Shareholders and Related Party Transactions..............................................                                   | 56   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 8.                                                                                                                                                | Financial Information.................................................................................................            | 56   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 9.                                                                                                                                                | The Offer and Listing.................................................................................................            | 57   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 10.                                                                                                                                               | Additional Information...............................................................................................             | 58   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 11.                                                                                                                                               | Quantitative and Qualitative Disclosures About Market Risk...............................                                         | 66   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 12.                                                                                                                                               | Description of Securities Other than Equity Securities...........................................                                 | 69   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Part II.                                                                                                                                               |                                                                                                                                   |      | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 13.                                                                                                                                               | Defaults, Dividend Arrearages and Delinquencies..................................................                                 | 69   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 14.                                                                                                                                               | Material Modifications to the Rights of Security Holders
      and Use of Proceeds...                                             | 69   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 15.                                                                                                                                               | Controls and Procedures............................................................................................               | 69   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 16.                                                                                                                                               | [Reserved]...................................................................................................................     | 70   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 16(A).                                                                                                                                            | Audit Committee Financial Expert.............................................................................                     | 70   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 16(B).                                                                                                                                            | Code of Ethics.............................................................................................................       | 70   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 16(C).                                                                                                                                            | Principal Accountant Fees and Services....................................................................                        | 70   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Part III.                                                                                                                                              |                                                                                                                                   |      | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 17.                                                                                                                                               | Financial Statements...................................................................................................           | 70   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 18.                                                                                                                                               | Financial Statements...................................................................................................           | 71   | 
|                                                                                                                                                       |                                                                                                                                   |      | 
|Item 19.                                                                                                                                               | Exhibits......................................................................................................................... | 71   | 

2

---





|Glossary of Terms           |                                                                                                                                                                                                                                                                                                                           
|--------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                            |                                                                                                                                                                                                                                                                                                                           
|Air drilling                | A method of drilling that uses compressed
        air as a medium for transporting drill cuttings to surface.                                                                                                                                                                                                             
|                            |                                                                                                                                                                                                                                                                                                                           
|Basal Quartz zone           | A name generally applied to the Ellerslie
        formation as it occupies the bottom sandstone of the Mannville
        Group of lower Cretaceous age about 124 millions years of age.                                                                                                                                 
|                            |                                                                                                                                                                                                                                                                                                                           
|Bbl or Barrel               | 42 U.S. gallons liquid volume of crude
        oil or natural gas liquids.                                                                                                                                                                                                                                                
|                            |                                                                                                                                                                                                                                                                                                                           
|Bcf                         | Billion cubic feet of gas. Usual expression
        of proved reserve gas volume.                                                                                                                                                                                                                                         
|                            |                                                                                                                                                                                                                                                                                                                           
|Belly River formation       | Late Cretaceous Age sandstones and shales
        deposited from 75 to 84 million years ago.                                                                                                                                                                                                                              
|                            |                                                                                                                                                                                                                                                                                                                           
|Blairmore formation         | Formation encompassing clastic sediments
        deposited in the Early Cretaceous Age from about 100 to 120 million years
        ago.                                                                                                                                                                                   
|                            |                                                                                                                                                                                                                                                                                                                           
|Blue Sky formation          | Sandstones of the Lower Cretaceous, about
        112 million years old, occurring in Northern Alberta and NE BC.                                                                                                                                                                                                         
|                            |                                                                                                                                                                                                                                                                                                                           
|BOE                         | Barrels of Oil Equivalent. Generally
        one barrel of oil equals six mcf of gas. Allows reserves of oil and gas
        to be added together.                                                                                                                                                                        
|                            |                                                                                                                                                                                                                                                                                                                           
|BOE/d                       | An expression of barrels of oil equivalent
        produced per day.                                                                                                                                                                                                                                                      
|                            |                                                                                                                                                                                                                                                                                                                           
|Carbonates                  | Rocks composed predominantly of Calcium
        Carbonate (CaCO3).                                                                                                                                                                                                                                                        
|                            |                                                                                                                                                                                                                                                                                                                           
|Condensate                  | A mixture comprising pentanes and heavier
        hydrocarbons recovered as a liquid from field separators, scrubbers or
        other gathering facilities or at the inlet of a processing plant before
        the gas is processed.                                                                                    
|                            |                                                                                                                                                                                                                                                                                                                           
|Cretaceous Age              | Rocks from 144 million to 66.4 million
        years of age.                                                                                                                                                                                                                                                              
|                            |                                                                                                                                                                                                                                                                                                                           
|Crown royalty               | An amount payable to the government of
        the applicable Canadian province in relation to the production of petroleum,
        natural gas or related hydrocarbons from an oil or gas well located on
        Crown lands.                                                                                           
|                            |                                                                                                                                                                                                                                                                                                                           
|Crude oil                   | A mixture, consisting mainly of pentanes
        and heavier hydrocarbons that may contain sulphur compounds, that is liquid
        at the conditions under which its volume is measured or estimated, but
        excluding such liquids obtained from the processing of natural gas.                                   
|                            |                                                                                                                                                                                                                                                                                                                           
|Depletion                   | The reduction in petroleum reserves due
        to production.                                                                                                                                                                                                                                                            
|                            |                                                                                                                                                                                                                                                                                                                           
|Development or developed    | Refers to the phase in which a proven
        oil or gas field is brought into production by drilling and completing
        production wells and the wells, in most cases, are connected to a petroleum
        gathering system.                                                                                        
|                            |                                                                                                                                                                                                                                                                                                                           
|Devonian Age                | Rocks from 408 million to 360 million
        years of age.                                                                                                                                                                                                                                                               
|                            |                                                                                                                                                                                                                                                                                                                           
|Discovery                   | The location, learned through drilling
        of a well, where there exists an accumulation of gas, condensate or oil
        reserves. The size of the reserves may be estimated but not precisely
        quantified and may or may not be commercially economic, depending on a
        number of factors.            
|                            |                                                                                                                                                                                                                                                                                                                           
|Drill stem test             | A method of packing off the pressure
        of drilling mud weight to allow a prospective oil or gas formation to
        flow into the drill stem pipe. Drill stem test results assist in evaluating
        the potential of the zone to flow or to be pumped commercially.                                            
|                            |                                                                                                                                                                                                                                                                                                                           
|Dry hole                    | A well drilled without finding commercially
        economic quantities of hydrocarbons.                                                                                                                                                                                                                                  
|                            |                                                                                                                                                                                                                                                                                                                           
|Ellerlsie zone or formation | A name applied to a group of sandstones
        that are clear and quartzose with good porosity and permeability for oil
        and gas about 124 millions years of age.                                                                                                                                                 
|                            |                                                                                                                                                                                                                                                                                                                           
|Exploration well            | A well drilled in a prospect without
        knowledge of the underlying sedimentary rock or the contents of the underlying
        rock.                                                                                                                                                                                 
|                            |                                                                                                                                                                                                                                                                                                                           
|Farmin                      | By way of agreement, a party earns (farmin)
        an interest in lands comprising petroleum and natural gas rights from
        another party by drilling a well or similar activity that evaluates, explores
        or develops the lands for the production of petroleum substances.                                 
|                            |                                                                                                                                                                                                                                                                                                                           
|Farmout                     | By way of agreement, a party gives up
        (farmout) an interest in lands comprising petroleum and natural gas rights
        to another party who earns the interest by drilling a well or similar
        activity that evaluates, explores or develops the lands for the production
        of petroleum substances.
|                            |                                                                                                                                                                                                                                                                                                                           
|Field                       | An area that is producing, or has been
        proven to be capable of producing, hydrocarbons.                                                                                                                                                                                                                           
|                            |                                                                                                                                                                                                                                                                                                                           
|Field netbacks              | Revenues from the sale of all commodities
        produced, less applicable resource and production royalties, less operating
        costs.                                                                                                                                                                              
|                            |                                                                                                                                                                                                                                                                                                                           
|Formation                   | A reference to a group of rocks of the
        same age extending over a substantial area of a basin.                                                                                                                                                                                                                     
|                            |                                                                                                                                                                                                                                                                                                                           

3

---





|                         |                                                                                                                                                                                                                                                                                                                                                                                
|------------------------ | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Freehold royalty         | An amount payable to a mineral
        rights holder in relation to the production of petroleum, natural gas
        or related hydrocarbons from an oil or gas well located on non-Crown lands.                                                                                                                                                                               
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|GAAP                     | Generally accepted accounting
        principles.                                                                                                                                                                                                                                                                                                                              
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Geology                  | The science relating to
        the history and development of the Earth.                                                                                                                                                                                                                                                                                                      
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Glauconite               | A sand group from the Upper
        Mannville (Lower Cretaceous Age) about 110 million years ago with a green
        mineral constituent.                                                                                                                                                                                                                                     
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Gross acres              | The total acreage in which
        the Company has an interest.                                                                                                                                                                                                                                                                                                                
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Hackett formation        | A sand package that occurs
        at the base of the Mannville Formation (Lower Cretaceous Age), 118 to
        120 million years old.                                                                                                                                                                                                                                        
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Hectare                  | A land measurement equaling
        2.471 acres.                                                                                                                                                                                                                                                                                                                               
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Horizontal well          | A vertical well bore that
        is gradually deviated (usually horizontally to 90o) in order
        to intersect the targeted formation.                                                                                                                                                                                                                                    
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Hydrocarbon              | The general term for oil,
        gas, condensate, liquids and other petroleum products.                                                                                                                                                                                                                                                                                       
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Jean Marie formation     | A patch reef carbonate reservoir
        within the Winterburn Group of the Upper Devonian Age, about 367 to 369
        million years old. The Jean Marie is found in NE British Columbia and
        is the stratigraphic equivalent to the lower Nisku formation in Alberta.                                                                                                
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|kilometer                | A measurement of distance
        equaling 0.621 miles or 3,281 feet.                                                                                                                                                                                                                                                                                                          
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Leduc (D-3) formation    | A reefal carbonate reservoir
        found within Woodbend Group of the Upper Devonian Age, about 369 to 373
        million years old. These ancient Leduc reefs were the initial target for
        oil and gas exploration in Alberta. Leduc No. 1, approximately 30 km.
        South of St. Albert, was the discovery well for conventional oil in Western
        Canada.
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Logs                     | Recordings from electrical
        and radioactive source devices that are run down wellbores to measure
        petrophysical properties of the adjacent rocks.                                                                                                                                                                                                               
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Lower Mannville gas      | Any gas sands found in the
        lower half of the Lower Cretaceous Age zones, about 110 million years
        old. These sands may comprise the Ostracod, Basal Quartz or Ellerlsie
        zones.                                                                                                                                                                          
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|mbbl                     | 1,000 barrels of oil and/or
        natural gas liquids.                                                                                                                                                                                                                                                                                                                       
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|mboe                     | 1,000 barrels of oil equivalent.
        See BOE for further details.                                                                                                                                                                                                                                                                                                        
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|mcf                      | 1,000 cubic feet of natural
        gas.                                                                                                                                                                                                                                                                                                                                       
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|mcf/d                    | 1,000 cubic feet of natural
        gas production per day. Usually used to express the production rate of
        a group of gas wells.                                                                                                                                                                                                                                       
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|meter                    | A physical measurement equaling
        3.281 feet.                                                                                                                                                                                                                                                                                                                            
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Mineral taxes (freehold) | An amount levied by the
        government of Alberta in relation to the production of petroleum, natural
        gas or related hydrocarbons from an oil or gas well located on non-government
        (freehold) lands in Alberta.                                                                                                                                           
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|mmcf                     | 1,000,000 cubic feet of
        natural gas.                                                                                                                                                                                                                                                                                                                                   
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|mmcf/d                   | 1,000,000 cubic feet of
        natural gas production per day. Usually used to express the production
        rate of a gas well or group of gas wells.                                                                                                                                                                                                                       
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Natural gas              | The lighter hydrocarbons
        and associated non-hydrocarbon substances occurring naturally in an underground
        reservoir, which under atmospheric conditions are essentially a gas, but
        that may contain liquids.                                                                                                                                            
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|NGLs                    | Natural gas liquids. Hydrocarbon
        components recovered from raw natural gas as liquids by processing through
        extraction plants or recovered from field separators, scrubbers or other
        gathering facilities. These liquids include the hydrocarbon components
        ethane, propane, butane and pentane plus, or combinations thereof.                 
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Net acres                | The percentage of gross
        acreage in which the Company has a working interest.                                                                                                                                                                                                                                                                                           
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Nisku (D-2) formation    | A reefal carbonate reservoir
        in the Winterburn Group of the Upper Devonian Age, about 367 to 369 million
        years old. The Nisku is found exclusively within Alberta but it is a stratigraphic
        equivalent to the Jean Marie formation in British Columbia.                                                                                                
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Ostracod zone            | Rocks from the Lower Cretaceous
        Age approximately 119 million years ago comprised of sandstones and marlstones
        that contain a small fossil named Ostracod.                                                                                                                                                                                                     
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Ostracod well            | A gas well capable of producing
        commercially from the Lower Cretaceous Age Ostracod zone.                                                                                                                                                                                                                                                                              
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Operator                 | That party to a joint venture
        agreement whose responsibility it is to carry out all exploratory, development,
        maintenance and record-keeping duties on behalf of other joint venture
        partners in relation to hydrocarbon extraction on the joint-ventured lands.                                                                                       
|                         |                                                                                                                                                                                                                                                                                                                                                                                
|Overriding royalty       | An amount payable to a third
        party other than crown or freehold in relation to the                                                                                                                                                                                                                                                                                     
|                         |                                                                                                                                                                                                                                                                                                                                                                                

4

---





|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|----------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                              | production of petroleum,
        natural gas or related hydrocarbons from an oil or gas well located on
        lands in which the interest of the third party usually arises out of a
        separate agreement.                                                                                                                                                                                                                                                                                                                                                                          
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Pentanes                      | A hydrocarbon by-product
        of natural gas generally referred to as condensate that is of the paraffin
        series having a chemical formula of C5H12 and having all its carbon atoms
        joined in a straight chain.                                                                                                                                                                                                                                                                                                                                                           
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Permeability                  | Capacity of a rock for transmitting
        a fluid.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Permit or licence area        | An area that is granted
        for a prescribed period of time for exploration, development or production
        under specific contractual or legislative conditions.                                                                                                                                                                                                                                                                                                                                                                                                                    
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Pipeline                      | A system of interconnected
        pipes that gather and transport hydrocarbons from a well or field to a
        processing plant or to a facility that is built to take the hydrocarbons
        for further transport, such as a gas liquefaction plant.                                                                                                                                                                                                                                                                                                                                 
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Probable reserves             | Those reserves that analysis
        of drilling, geological, geophysical and engineering data do not demonstrate
        to be proved with current technology and under existing economic conditions,
        but where such analysis suggests the likelihood of their existence and
        future recovery. Probable reserves to be obtained will be the increased
        recovery beyond estimated proved reserves that can be realistically estimated
        for the pool through enhanced recovery processes that can reasonably be
        expected to be instituted in the future.
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Proved reserves               | Those reserves estimated
        as recoverable with current technology and under existing economic conditions,
        from that portion of a reservoir that can be reasonably evaluated as economically
        productive through analysis of drilling, geological, geophysical and engineering
        data. This includes the reserves to be obtained by enhanced recovery processes
        demonstrated to be economically and technically successful in the subject
        reservoir.                                                                                              
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Quartzose                     | Rocks composed of mostly
        quartz.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Raw gas                       | Gaseous effluent from a
        wellhead or pipeline that is not processed. Contains water vapor, carbon
        dioxide, nitrogen and possibly hydrogen sulphide (H2S) gas.                                                                                                                                                                                                                                                                                                                                                                                                                
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Reservoir rock                | Porous limestones, dolomites
        or sandstones that can trap oil and/or gas in interconnected holes, like
        a sponge.                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Royalty                       | A stated or determinable
        percentage of the proceeds received from the sale of hydrocarbons calculated
        as prescribed in applicable legislation or in the agreement with the royalty
        holder.                                                                                                                                                                                                                                                                                                                                                                          
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Seals                         | Impermeable barriers to
        hydrocarbon flow such as shale, lime muds, salt or anhydrite.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Seismic                       | A geophysical technique
        using low frequency sound waves to determine the subsurface structure
        of sedimentary rocks.                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Sour gas                      | Raw gas with an amount of
        hydrogen sulphide (H2S) gas above pipeline requirements of
        10 parts H2S per million raw gas.                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Source rock                   | Usually shales and clays
        with a high carbon content deposited in a marine environment.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Sweet gas                     | Natural gas containing no
        hydrogen sulphide (H2S) gas.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Stabilized absolute open flow | The maximum rate of gas
        production that a wellhead will produce assuming no backpressure when
        the well is stable.                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Tertiary sediment             | Soft rock of sands, clays,
        coals and siltstones from 66.4 to 1.6 million years old.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Undeveloped                   | Prior to the time in which
        a proven oil or gas field is brought into production by drilling and completing
        production wells.                                                                                                                                                                                                                                                                                                                                                                                                                                                
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Vertical well                 | A well bore that intersects
        the section(s) containing hydrocarbons at about 90o.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|                              |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|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.

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

Item 1.      Identity of Directors,
  Senior Management and Advisers

Not
  applicable.

Item 2.      Offer Statistics
  and Expected Timetable

Not
  applicable.

Item 3.      Key Information

Selected Financial Data

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

Selected Financial Data Presented According to Canadian GAAP

|                             |             |   |         |   |                |   |         |   |         |  
|---------------------------- | ----------- | - | ------- | - | -------------- | - | ------- | - | ------- | -
|                             | As at       |   |         |   |                |   |         |   |         |  
|                             | December 31 |   |         |   | As at March 31 |  
|                             |             |   |         |   |                |   |         |   |         |  
|($ 000s)                    | 2002        |   | 2002    |   | 2001           |   | 2000    |   | 1999    |  
|                             |             |   |         |   |                |   |         |   |         |  
|Balance Sheets               |             |   |         |   |                |   |         |   |         |  
|Working capital (deficiency) | (16,818     | ) | (13,281 | ) | 1,969          |   | (3,716  | ) | (1,225  | )
|Total assets                 | 43,647      |   | 37,152  |   | 29,991         |   | 18,811  |   | 12,487  |  
|Current liabilities          | 23,729      |   | 19,625  |   | 6,210          |   | 7,717   |   | 3,950   |  
|Long-term liabilities        | 991         |   | 824     |   | 540            |   | 402     |   | 404     |  
|Deferred gain on sale        | -           |   | 109     |   | 340            |   | 652     |   | 997     |  
|Future income tax liability  | 682         |   | -       |   | 2,955          |   | -       |   | -       |  
|Net assets                   | 18,245      |   | 16,593  |   | 19,947         |   | 10,041  |   | 7,136   |  
|Share capital                | 20,721      |   | 20,915  |   | 20,642         |   | 20,420  |   | 21,080  |  
|Deficit                      | (2,476      | ) | (4,322  | ) | (695           | ) | (10,379 | ) | (13,944 | )
|                             |             |   |         |   |                |   |         |   |         |  

6

---





|                                           |            |  |                                              |   |        |  |        |  |        | 
|------------------------------------------ | ---------- |  | -------------------------------------------- | - | ------ |  | ------ |  | ------ | 
|                                           | Nine-Month |  |                                              |   |        |  |        |  |        | 
|                                           | Fiscal     |  |                                              |   |        |  |        |  |        | 
|                                           | Transition |  | For the 12-month period ended
      March 31 |  
|                                           |            |  |                                              |   |        |  |        |  |        | 
|($ 000s)                                  | 2002       |  | 2002                                         |   | 2001   |  | 2000   |  | 1999   | 
|                                           |            |  |                                              |   |        |  |        |  |        | 
|Statements of Operations                   |            |  |                                              |   |        |  |        |  |        | 
|Gross revenues                             | 24,123     |  | 26,402                                       |   | 34,463 |  | 15,770 |  | 9,495  | 
|Net revenues                               | 13,309     |  | 14,215                                       |   | 20,524 |  | 7,438  |  | 3,857  | 
|Cash flow from operations 1                | 10,723     |  | 11,337                                       |   | 18,168 |  | 5,634  |  | 2,634  | 
|Cash flow per share, basic ($)             | 0.53       |  | 0.55                                         |   | 0.91   |  | 0.29   |  | 0.13   | 
|Cash flow per share, diluted ($)           | 0.52       |  | 0.55                                         |   | 0.89   |  | 0.28   |  | 0.13   | 
|Earnings (loss) before taxes               | 3,146      |  | (5,419                                       | ) | 14,449 |  | 2,871  |  | 1,212  | 
|Net earnings (loss)                        | 1,978      |  | (3,519                                       | ) | 9,714  |  | 4,079  |  | 1,212  | 
|Common shares  weighted avg. (# 000s)    | 20,357     |  | 20,365                                       |   | 19,938 |  | 19,710 |  | 19,892 | 
|Net (loss) earnings per share, basic ($)   | 0.10       |  | (0.17                                        | ) | 0.49   |  | 0.21   |  | 0.06   | 
|Net (loss) earnings per share, diluted ($) | 0.10       |  | (0.17                                        | ) | 0.48   |  | 0.20   |  | 0.06   | 

|(1) | Cash flow from operations
        is a non-GAAP measure that does not have standardized meaning as prescribed
        by GAAP and is therefore unlikely to be comparable to similar measures
        presented by other companies. We consider it a key measure as it demonstrates
        our ability to generate the cash flow necessary to fund future growth
        through capital investment and to repay debt. Below is the determination
        of the non-GAAP measure by utilizing existing GAAP measures.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |                                                    | Nine-      |   |      |   |        |  |     |   |             |  
| | -------------------------------------------------- | ---------- | - | ---- | - | ------ |  | --- | - | ----------- | -
| |                                                    | Month      |   |      |   |        |  |     |   |             |  
| |                                                    | Fiscal     |   |      |   |        |  |     |   |             |  
| |                                                    | Transition |   | %    |   | Fiscal |  | %   |   |             |  
| | ($ 000s)                                          | 2002       |   | Chg  |   | 2002   |  | Chg |   | Fiscal 2001 |  
| |                                                    |            |   |      |   |        |  |     |   |             |  
| | Cash flow from operating activities (GAAP measure) | 11,370     |   | 16   |   | 9,779  |  | (49 | ) | 19,264      |  
| | Changes in non-cash working capital (GAAP measure) | (647       | ) | (142 | ) | 1,559  |  | 242 |   | (1,096      | )
| |                                                    |            |   |      |   |        |  |     |   |             |  
| | Cash flow from operations (non-GAAP measure)       | 10,723     |   | (5   | ) | 11,337 |  | (38 | ) | 18,168      |  
| |                                                    |            |   |      |   |        |  |     |   |             |  

Selected Financial Data Presented According to U.S. GAAP

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

|                                                                                                          |             |   |        |   |                |   |         |   |         |  
|--------------------------------------------------------------------------------------------------------- | ----------- | - | ------ | - | -------------- | - | ------- | - | ------- | -
|                                                                                                          | As at       |   |        |   |                |   |         |   |         |  
|                                                                                                          | December 31 |   |        |   | As at March 31 |  
|                                                                                                          |             |   |        |   |                |   |         |   |         |  
|($ 000s)                                                                                                 | 2002        |   | 2002   |   | 2001           |   | 2000    |   | 1999    |  
|                                                                                                          |             |   |        |   |                |   |         |   |         |  
|                                                                                                          |             |   |        |   |                |   |         |   |         |  
|After adjusting for certain differences, selected
      balance sheet items under U.S. GAAP would become: |             |   |        |   |                |   |         |   |         |  
|                                                                                                          |             |   |        |   |                |   |         |   |         |  
|Balance Sheets                                                                                            |             |   |        |   |                |   |         |   |         |  
|Future income tax asset                                                                                   | -           |   | 371    |   | -              |   | 242     |   | -       |  
|Future income tax liability                                                                               | 541         |   | -      |   | 3,532          |   | -       |   | -       |  
|Natural gas and oil interests                                                                             | 36,236      |   | 30,150 |   | 21,679         |   | 13,721  |   | 9,702   |  
|Share capital *                                                                                           | 21,694      |   | 21,883 |   | 21,610         |   | 21,368  |   | 21,802  |  
|Deficit                                                                                                   | (1,640      | ) | (5,422 | ) | (2,356         | ) | (11,473 | ) | (14,896 | )
|                                                                                                          |             |   |        |   |                |   |         |   |         |  

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

7

---





|                                                        |            |   |                                              |   |       |   |       |   |       |  
|------------------------------------------------------- | ---------- | - | -------------------------------------------- | - | ----- | - | ----- | - | ----- | -
|                                                        | Nine-Month |   |                                              |   |       |   |       |   |       |  
|                                                        | Fiscal     |   |                                              |   |       |   |       |   |       |  
|                                                        | Transition |   | For the 12-month period ended
      March 31 |  
|                                                        |            |   |                                              |   |       |   |       |   |       |  
|($ 000s)                                               | 2002       |   | 2002                                         |   | 2001  |   | 2000  |   | 1999  |  
|                                                        |            |   |                                              |   |       |   |       |   |       |  
|Statements of Operations                                |            |   |                                              |   |       |   |       |   |       |  
|Net (loss) earnings under Canadian GAAP                 | 1,978      |   | (3,519                                       | ) | 9,714 |   | 4,079 |   | 1,212 |  
|Reconciling adjustments *                               |            |   |                                              |   |       |   |       |   |       |  
|Compensatory stock options
      issued                 | -          |   | -                                            |   | -     |   | -     |   | (8    | )
|Options issued for services                             | (5         | ) | -                                            |   | (20   | ) | -     |   | -     |  
|Ceiling test adjustment to
      natural gas properties | (332       | ) | (216                                         | ) | -     |   | (145  | ) | -     |  
|Income taxes                                            | 141        |   | 669                                          |   | (577  | ) | -     |   | -     |  
|Net (loss) earnings under U.S. GAAP                     | 1,782      |   | (3,066                                       | ) | 9,117 |   | 3,934 |   | 1,204 |  
|Net (loss) earnings/share, U.S. GAAP basic
      ($)    | 0.09       |   | (0.15                                        | ) | 0.46  |   | 0.20  |   | 0.06  |  
|Net (loss) earnings/share, U.S. GAAP diluted
      ($)  | 0.09       |   | (0.15                                        | ) | 0.45  |   | 0.19  |   | 0.06  |  

Dividends

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

Exchange Rates

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

Exchange Rates for Canadian Versus U.S. Dollars

The
  exchange rate as of May 5, 2003 was CDN $1.4134 per U.S. $1.00.

|Exchange Rates for Canadian Versus U.S.
      Dollars |        |  |        | 
|----------------------------------------------------- | ------ |  | ------ | 
|(High/low rates for latest six months)                | High   |  | Low    | 
|                                                      |        |  |        | 
|April, 2003                                           | 1.4843 |  | 1.4336 | 
|March, 2003                                           | 1.4905 |  | 1.4659 | 
|February, 2003                                        | 1.5303 |  | 1.4928 | 
|January, 2003                                         | 1.5750 |  | 1.5220 | 
|December, 2002                                        | 1.5800 |  | 1.5478 | 
|November , 2002                                       | 1.5903 |  | 1.5528 | 
|                                                      |        |  |        | 

|Exchange Rates for Canadian Versus U.S.
      Dollars |  |             | 
|----------------------------------------------------- |  | ----------- | 
|                                                      |  | Average ($) | 
|                                                      |  |             | 
|For the nine-month period ended December 31           |  |             | 
|2002                                                  |  | 1.56        | 
|For the twelve-month periods ended March 31           |  |             | 
|2002                                                  |  | 1.57        | 
|2001                                                  |  | 1.50        | 
|2000                                                  |  | 1.47        | 
|1999                                                  |  | 1.50        | 
|                                                      |  |             | 

8

---





Capitalization and Indebtedness

Not
  applicable.

Reasons for the Offer and Use of Proceeds

Not
  applicable.

Risk Factors

Business Risk Management

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

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

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

Commodity
  Price Fluctuations

Our
  products, including natural gas, NGLs and oil, and other hydrocarbon products,
  are commodities. Because our contracts do not fix a long-term price for the
  products we purchase or sell, market changes in the price of such products have
  a direct and immediate effect (whether favorable or adverse) upon our revenues
  and profitability. Prices for products may be subject to material change in
  response to relatively minor changes in supply and demand, general economic
  conditions and other market conditions over which we have no control. Other
  conditions affecting our business include the level of domestic oil and gas
  production, the availability and prices of competing commodities and of alternative
  energy sources, the availability of local, intraprovincial and interprovincial
  transportation systems with adequate capacity, the proximity of gas production
  to gas pipelines and facilities, the availability of pipeline capacity, government
  regulation, the seasons, the weather and the impact of energy conservation efforts.

Availability
  of Natural Gas Supply

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

Dependence
  on Third Party Pipelines

In
  Nine-Month Fiscal Transition 2002, substantially all our sales of natural gas
  were effected through deliveries to local third-party gathering systems to processing
  plants in Alberta owned by ATCO Midstream Ltd. and Northwestern Utilities Limited.
  In addition, we rely on access to interprovincial pipelines for the sale and
  distribution of substantially all of our gas. As a result, a curtailment of
  our sale of natural gas by pipelines or by third-party gathering systems, an
  impairment of our ability to transport natural gas on interprovincial pipelines
  or a material increase in the rates charged to us for the transportation of
  natural gas by reason of a change in federal or provincial regulations or for
  any other reason, could have a material adverse effect upon us. In such event,
  we would have to obtain other transportation arrangements or we would have to
  construct alternative pipelines. There can be no assurance that we would have
  economical transportation alternatives or that it would be feasible for us to
  construct pipelines. In the event such circumstances were to occur, our field
  netbacks from the affected wells would be suspended until, and if, such circumstances
  could be resolved.

9

---





**Operating
  History and Significant Historical Operating Losses**

We
  commenced operations in 1979. We have one major property, that began as a one-well
  producing property in 1985. By fiscal 1999, the property became our major producing
  property with up to twenty-four producing natural gas and oil wells. Due to
  the relatively short five-year production history from the majority of wells
  on the property, proved reserves and future production attributable to this
  property are somewhat more susceptible to estimation discrepancies than fields
  with longer production histories.

We
  first experienced earnings in fiscal 1999 of $1,211,638. In fiscal 2000 and
  Fiscal 2001, we reported earnings of $4,078,577 and $9,714,030 respectively
  and in Fiscal 2002, we returned to a loss of $3,519,085. In Nine-Month Fiscal
  Transition 2002, we again reported earnings of $1,977,663. As at December 31,
  2002, we had an accumulated deficit of $2,475,932. Our future viability should
  be considered in light of the risks and difficulties frequently encountered
  by companies engaged in the junior stages of oil and gas exploration, development
  and production activities.

Dependence
  on Key Personnel

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

Risks
  Pertaining to Acquisitions and Joint Ventures

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

Potential
  Variability in Quarterly Operating Results

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

Dependence
  on One Major Property

Currently,
  our major producing asset is our property located at St. Albert, Alberta. While
  the St. Albert property as of December 31, 2002 has developed into 16 separate,
  mutually-exclusive oil and gas pools stacked in 7 productive formations (4 natural
  gas and 3 crude oil), each pool has its own reserves and future production risk,
  and thus it is important for us to establish producing fields in other areas.
  Unless we can successfully drill for or acquire economically viable reserves
  of natural gas and crude oil in other areas, as our production depletes the
  reserves at St. Albert, our revenue may be materially adversely affected.

Limited
  Financial Resources

We
  expect to continue to produce enough cash flow, along with our bank credit facility,
  to support land acquisitions, drilling operations, facilities construction and
  general /administration costs. At this time, we believe that our cash flow and
  credit facility will be sufficient to support our business activities without
  securing significant additional financing in the near future. If it were to
  become necessary to raise significant additional financing, any arrangements
  that may be entered into could be expensive to us. There can be no assurance
  that we will be able to raise additional capital in light of factors such as
  the market demand for our securities, the state of financial markets for independent
  oil companies (including the markets for debt), oil and gas prices and general
  market conditions. (See "Operating and Financial Review and Prospects" for a
  discussion of our capital budget).

10

---





We
  expect to continue using our bank credit facility to borrow funds to supplement
  our available cash. The amount we may borrow under the credit facility may not
  exceed a borrowing base determined by the lender based on its projections of
  our future production, future costs of production, taxes, commodity prices and
  other factors. We cannot control the assumptions the lender uses to calculate
  the borrowing base. The lender may, without our consent, adjust the borrowing
  base at any time. If our borrowings under the credit facility exceed the borrowing
  base, the lender may require that we repay the excess. If this were to occur,
  we may have to sell assets or seek financing from other sources. We can make
  no assurances that we would be successful in selling assets at prices acceptable
  to us or arranging substitute financing. For a description of our bank credit
  facility and its principal terms and conditions, see "Operating and Financial
  Review and Prospects under Item 5, and Note 4 attached to the Financial
  Statements under Item 17 of this Transition Report.

Exploration and Development Risks

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

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

Operating Hazards and Uninsured Risks

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

Operating Risk

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

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


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

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

11

---





Drilling Plans Subject to Change

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

Replacement of Reserves

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

Dependence on Few Customers

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

Estimating of Reserves and Future Net Cash Flows Risk

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

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

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

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

12

---





Shortage of Supplies and Equipment

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

Restoration, Safety and Environmental Risk

All our operations are in western Canada and, in particular, the western provinces
  of Alberta and British Columbia. Certain laws and regulations exist that require
  companies engaged in petroleum activities to obtain necessary safety and environmental
  permits to operate. Such legislation may restrict or delay us from conducting
  operations in certain geographical areas. Further, such laws and regulations
  may impose liability on us for remedial and clean-up costs, personal injuries
  related to safety and environmental damages.

To ensure that we provide for future estimated removal and site restoration
  costs, we recognized $0.2 million in our Statement of Operations and Deficit
  during Nine-Month Fiscal Transition 2002, bringing our total recognized amount
  in our December 31, 2002 Balance Sheet to $1.0 million. We engage independent
  engineering consultants to assist in assessing our total future liabilities
  related to removal and clean-up costs. While we cannot predict their ultimate
  cost, we currently estimate the future cost to clean up all our operating facilities
  to be $2.1 million.

While our safety and environmental activities have been prudent and have enabled
  us to operate successfully in managing such risks, there can be no assurance
  that we will always be successful in protecting ourselves from the impact of
  all such risks. Consistent with our growth in other areas, we seek opportunities
  for performance improvement in our operating practices. 
  Government Regulation and Environmental Matters

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

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

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

Kyoto Protocol Risk

The Kyoto Protocol treaty (Protocol) was established to reduce emissions of
  greenhouse gases (GHG) that are believed to contribute to increasing Earths
  surface temperatures and affecting the global climate change. Canada adopted
  the Kyoto Protocol in December 1997. The Protocol establishes commitments to
  reduce GHG internationally and Canada has committed to meet a 6% reduction over
  base-year 1990 during the period 2008 to 2012. While we believe we are a low-emission
  producer, it is not possible for us to predict the impact of how Protocol-related
  issues will ultimately be resolved and to what extent their impact will affect
  our future unit operating costs and capital expenditures.

Interruption From Severe Weather

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

13

---





Competition

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

Item 4.     Our Information

Our History and Development

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

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

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

Capital Expenditures

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

|                               | Nine-Month Fiscal |  | %   |   |             |  | %    |   |             | 
|------------------------------ | ----------------- |  | --- | - | ----------- |  | ---- | - | ----------- | 
|($000s)                       | Transition 2002   |  | chg |   | Fiscal 2002 |  | chg  |   | Fiscal 2001 | 
|                               |                   |  |     |   |             |  |      |   |             | 
|Drilling, completions, tie-ins | 9,146             |  | 19  |   | 7,678       |  | 106  |   | 6,939       | 
|Facilities                     | 780               |  | (56 | ) | 1,757       |  | (50  | ) | 3,522       | 
|Land acquisitions              | 2,568             |  | (80 | ) | 12,560      |  | 1105 |   | 1,042       | 
|Corporate office               | 84                |  | (28 | ) | 116         |  | 47   |   | 79          | 
|                               |                   |  |     |   |             |  |      |   |             | 
|Total                          | 12,578            |  | (43 | ) | 22,111      |  | 91   |   | 11,582      | 
|                               |                   |  |     |   |             |  |      |   |             | 

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

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

| | •                                                              | 48% in Alberta development properties to maintain and grow
      existing production levels; and                  
| | -------------------------------------------------------------- | ------------------------------------------------------------------------------------------------------------------
| | •                                                              | 52% in British Columbia exploration properties for potential
      longer-term production growth.                 
| |                                                                |                                                                                                                   
| | We invested our capital in the following specific
      areas:
| | Alberta                                                       
| | •                                                              | Exploration - drilling, completions and tie-ins totalled $0.2 million,
        most of which was spent at Halkirk;



14

---





| | •                                                              | Development of core properties 
        drilling, completions and tie-ins totalled $3.9 million, 74% of which
        was spent at St. Albert and 26% at Halkirk;                                                                 
| | -------------------------------------------------------------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | •                                                              | Facilities - $0.8 million to acquire
        an increased interest in gas processing facilities at St. Albert pursuant
        to a Sale and Leaseback arrangement, as described in Note 5 to our Financial
        Statements; and
| | •                                                              | Land  acquisitions totalled $1.2
        million, 94% of which was to purchase various working and royalty interests
        at St. Albert.                                                                                       
| | British Columbia                                              
| | •                                                              | Exploration  drilling, completions and tie-ins
        totaled $5.0 million, all of which was spent in the Cypress/Chowade area;
        and                                                                                      
| | •                                                              | Land - acquisitions totalled $1.4 million, 90% of which
        was spent at Orion.                                                                                                                                                
| |                                                                |                                                                                                                                                                                                                                    
| | Fiscal 2002                                                   
| | We invested our capital in the following specific
      areas:
| | Alberta                                                       
| | •                                                              | Exploration and Development  drilling, completions
        and tie-ins totalled $7.7 million, of which 95% was spent at St. Albert;
        and                                                                                   
| | •                                                              | Facilities and Land  totalled $14.4 million,
        most of which was spent to acquire additional working interests at St.
        Albert.                                                                                       
| |                                                                |                                                                                                                                                                                                                                    
| | Fiscal 2001                                                   
| | We invested our capital in the following specific
      areas:
| | Alberta                                                       
| | •                                                              | Exploration and Development  drilling, completions
        and tie-ins totaled $5.7 million, 53% of which was spent at St. Albert
        and the balance at Peavey/Morinville; and                                               
| | •                                                              | Facilities and Land  totalled $4.6 million,
        most of which was spent at Peavey/Morinville and Halkirk.                                                                                                                     
| | British Columbia                                              
| | •                                                              | Exploration and Development  drilling, completions
        and tie-ins totalled $1.3 million, all of which was spent at Orion.                                                                                                    

Exploration Expenses

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

|                      | Nine Month Fiscal |  | %   |   |             |  | %   |   |             | 
|--------------------- | ----------------- |  | --- | - | ----------- |  | --- | - | ----------- | 
|($ 000s)             | Transition 2002   |  | chg |   | Fiscal 2002 |  | chg |   | Fiscal 2001 | 
|                      |                   |  |     |   |             |  |     |   |             | 
|Drilling              | 325               |  | (91 | ) | 3,821       |  | 472 |   | 668         | 
|Seismic data activity | 847               |  | 31  |   | 649         |  | (41 | ) | 1,102       | 
|Other                 | 187               |  | 6   |   | 176         |  | 14  |   | 153         | 
|                      |                   |  |     |   |             |  |     |   |             | 
|Total                 | 1,359             |  | (71 | ) | 4,646       |  | 142 |   | 1,923       | 
|                      |                   |  |     |   |             |  |     |   |             | 

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





15

---





Capital Expenditures and Exploration Expenses Anticipated in 2003

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

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

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

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

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

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

Recent Material Events

We have no recent material events to report.

Share Repurchases

During the last three reporting periods, we spent $0.7 million on the re-purchase
  and cancellation of over 0.4 million of our outstanding shares of common stock
  at prices ranging from $1.54 to $1.72 per share.

Business Overview

General

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

Concentration of Commodities

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

16

---





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

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

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

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

Concentration of Operations

Our main producing property is located at St. Albert, Alberta. Of our total
  production in Nine-Month Fiscal Transition 2002, 85% came from the St. Albert
  property. The remainder originated from six other Alberta fields: Halkirk, Peavey/Morinville,
  Alexander, Simonette, Stanmore and Westlock. In Fiscal 2002, 84% of our production
  came from the St. Albert field, while the remainder came from six other fields:
  Peavey/Morinville, Halkirk, Westlock, Simonette and Stanmore. In Fiscal 2001,
  82% of our production came from the St. Albert field, while the remainder originated
  from five other fields: Peavey/Morinville, Westlock, Simonette, Redwater and
  Stanmore.

Revenue Breakdown

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

Natural Gas, Natural Gas Liquids and Crude Oil Revenue

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

|                    | Nine Month Fiscal |  | %   |   |             |  | %   |   |             | 
|------------------- | ----------------- |  | --- | - | ----------- |  | --- | - | ----------- | 
|($ 000s)           | Transition 2002   |  | chg |   | Fiscal 2002 |  | chg |   | Fiscal 2001 | 
|                    |                   |  |     |   |             |  |     |   |             | 
|Natural gas         | 17,058            |  | (19 | ) | 20,944      |  | (25 | ) | 28,006      | 
|Natural gas liquids | 4,012             |  | (10 | ) | 4,442       |  | (25 | ) | 5,935       | 
|Crude oil           | 3,053             |  | 200 |   | 1,016       |  | 95  |   | 522         | 
|                    |                   |  |     |   |             |  |     |   |             | 
|Total               | 24,123            |  | (9  | ) | 26,402      |  | (23 | ) | 34,463      | 
|                    |                   |  |     |   |             |  |     |   |             | 

Seasonality and Raw Materials

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

Natural gas is becoming increasingly important as an energy source to power
  natural gas-fired electric power

17

---





generating facilities (co-gen facilities). We believe that
  as more co-gen facilities are approved, constructed and put into operation,
  the demand for natural gas during shoulder seasons will remain relatively strong.

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

Marketing

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

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

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

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

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

Supply Contracts or Agreements

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

Competition

Presently, we regularly compete with other companies in bidding for the acquisition
  of petroleum interests from the Alberta and British Columbia governments and
  other corporations or individuals holding such interests. Further, we regularly
  compete for the availability of drilling rigs, production equipment, processing
  facilities, pipeline capacity and other transportation services. We do not have
  a competitive position that allows us any material or significant advantages
  compared to other companies within the same industry. Many competitors have
  substantially greater financial and other resources than we do. For example,
  in the 2002 Canadian Energy Survey of 2001 Results prepared by PriceWaterhouseCoopers,
  we ranked thirty-sixth and thirty-fifth in size out of one hundred Canadian
  exploration and production companies according to gross revenues and cash flow
  from operations, respectively.

Governmental Regulations

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

| | • | requirements to acquire permits before
        commencement of drilling operations;                                                                     
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | the proximity of hydrocarbon pipelines
        or other economically-feasible transportation;                                                           
| | • | requirements to restrict the substances
        that can be released into the environment in connection with drilling
        and production activities;
| | • | limitations on, or prohibitions to, drilling in protected
        areas such as offshore areas; and                                                     
| | • | requirements to mitigate and remediate the effects
        caused by drilling and production operations.                                                



18

---





Properties, Plant and Equipment

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

|Central Alberta   | British Columbia | Southern Saskatchewan            
|----------------- | ---------------- | ---------------------------------
|                  |                  |                                  
|St. Albert        | Stanmore         | Cypress (northeastern B.C.)      
|Halkirk           | Westlock         | Orion (northeastern B.C.)        
|Peavey/Morinville | Quirk Creek      | Fraser Valley (southwestern B.C.)
|Alexander         | Wimborne         |                                  
|Simonette         |                  |                                  

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

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

Land Holdings (acres)As at December 31, 2002

|                      | Developed |  |        |  | Undeveloped |  |        |  | Total   |  |         |  | Weighted     | 
|--------------------- | --------- |  | ------ |  | ----------- |  | ------ |  | ------- |  | ------- |  | ------------ | 
|Area                  | Gross     |  | Net    |  | Gross       |  | Net    |  | Gross   |  | Net     |  | Avg WI % (1) | 
|                      |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|Alberta               |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|St. Albert            | 9,379     |  | 6,101  |  | 5,372       |  | 3,936  |  | 14,751  |  | 10,037  |  | 68%          | 
|Halkirk               | 3,840     |  | 3,456  |  | 3,200       |  | 3,182  |  | 7,040   |  | 6,638   |  | 94%          | 
|Peavey/Morinville     | 7,203     |  | 4,931  |  | 5,069       |  | 3,758  |  | 12,272  |  | 8,689   |  | 71%          | 
|Quirk Creek           | 640       |  | 320    |  | 10,720      |  | 5,360  |  | 11,360  |  | 5,680   |  | 50%          | 
|Wimborne              | -         |  | -      |  | 3,200       |  | 3,200  |  | 3,200   |  | 3,200   |  | 100%         | 
|Other                 | 3,689     |  | 2,731  |  | 3,360       |  | 3,072  |  | 7,049   |  | 5,803   |  | 82%          | 
|                      |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|                      | 24,751    |  | 17,539 |  | 30,921      |  | 22,508 |  | 55,672  |  | 40,047  |  | 72%          | 
|                      |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|British Columbia      |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|Cypress/Chowade       | 3,499     |  | 1,749  |  | 12,010      |  | 4,028  |  | 15,509  |  | 5,777   |  | 37%          | 
|Orion                 | 1,920     |  | 960    |  | 64,485      |  | 45,682 |  | 66,405  |  | 46,642  |  | 70%          | 
|Fraser Valley         | -         |  | -      |  | 54,502      |  | 18,278 |  | 54,502  |  | 18,278  |  | 34%          | 
|                      |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|                      | 5,419     |  | 2,709  |  | 130,997     |  | 67,988 |  | 136,416 |  | 70,697  |  | 52%          | 
|                      |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|Total to Dec 31, 2002 | 30,170    |  | 20,248 |  | 161,918     |  | 90,496 |  | 192,088 |  | 110,744 |  | 58%          | 
|Total to Mar 31, 2002 | 24,110    |  | 17,089 |  | 126,061     |  | 69,162 |  | 150,171 |  | 86,251  |  | 57%          | 
|                      |           |  |        |  |             |  |        |  |         |  |         |  |              | 
|Increase (decrease)   | 6,060     |  | 3,159  |  | 35,857      |  | 21,334 |  | 41,917  |  | 24,493  |  | 1%           | 
|Increase (decrease) % | 25%       |  | 18%    |  | 28%         |  | 31%    |  | 28%     |  | 28%     |  | 1%           | 
|                      |           |  |        |  |             |  |        |  |         |  |         |  |              | 

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

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

19

---





|                  |               |         |                | Future      |             |         
|----------------- | ------------- | ------- | -------------- | ----------- | ----------- | --------
|                  | Percentage    |         | New            | Prospects   |             | 2003(4) 
|                  | Of            |         | Frontier       | For         | Reserves    | Activity
|                  | Production(1) | Core(2) | Exploration(3) | Development | Established | Planned 
|                  |               |         |                |             |             |         
|Alberta           |               |         |                |             |             |         
|St. Albert        | 85            | x       |                | x           | x           | x       
|Halkirk           | 7             | x       |                | x           | x           | x       
|Peavey/Morinville | 3             |         |                |             | x           |         
|Alexander         | 2             |         |                |             | x           |         
|Simonette         | 1             |         |                |             | x           |         
|Stanmore          | 1             |         |                |             | x           |         
|Westlock          | 1             |         |                |             | x           |         
|Quirk Creek       |               |         | x              | x           |             |         
|Wimborne          |               |         |                | x           |             | x       
|                  |               |         |                |             |             |         
|                  | 100           |         |                |             |             |         
|                  |               |         |                |             |             |         
|British Columbia  |               |         |                |             |             |         
|Cypress/Chowade   |               | x       | x              | x           | x           | x       
|Orion             |               |         | x              | x           |             | x       
|Fraser Valley     |               |         | x              | x           |             |         
|                  |               |         |                |             |             |         

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

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

|Alberta Properties           |   |                                                                                                                                                                                                                                                                                                                                                                              
|---------------------------- | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                             |   |                                                                                                                                                                                                                                                                                                                                                                              
|St. Albert                   | • | St.
        Albert is located in central Alberta near the City of Edmonton.                                                                                                                                                                                                                                                                                                  
|                             |   |                                                                                                                                                                                                                                                                                                                                                                              
|Geological
      Description | • | St
        Albert is comprised of sixteen separate Cretaceous-aged natural gas and
        Devonian-aged crude oil pools stacked in seven productive formations,
        four natural gas and three crude oil. We consider the St. Albert property
        as several core properties in one, as this high concentration of pools
        in one property is industry unique.
|                             | • | Historically,
        the property has produced in excess of 22.5 million barrels of crude oil
        and 109 billion cubic feet of raw natural gas.                                                                                                                                                                                                                        
|                             | • | The
        area is prospective for remaining recoverable crude oil from six established
        pools in the Leduc (D-3), Nisku (D-2) and Wabamun (D-1) formations.                                                                                                                                                                                                         
|                             |   |                                                                                                                                                                                                                                                                                                                                                                              
|Land
      holdings          | • | We
        hold 14,751 acres (10,037 net) under lease.                                                                                                                                                                                                                                                                                                                       
|                             |   |                                                                                                                                                                                                                                                                                                                                                                              
|Wells
      and facilities   | • | We
        own a 75% working interest (WI) in 22 producing natural gas wells;                                                                                                                                                                                                                                                                                                
|                             | • | Our
        ownership ranges from 44% to 77% WI in four producing natural gas wells.                                                                                                                                                                                                                                                                                         
|                             | • | We
        own a 75% WI in eight producing crude oil wells;                                                                                                                                                                                                                                                                                                                  
|                             | • | We
        own a 75% WI in one oil facility (battery), one solution gas plant, one
        sour gas compressor, two sweet gas compressors and a 13-km , 6”
        sour gas pipeline.                                                                                                                                                                                        
|                             |   |                                                                                                                                                                                                                                                                                                                                                                              
|Operating
      activities   | • | We
        drilled a successful D-3 oil well (location 06-25) by re-entering a previously
        suspended well bore, cutting a window in the casing below the Mannville
        formation and directionally drilling to a new seismically identified bottom
        hole location.                                                                                         
|                             | • | The
        oil well (location 06-25) confirmed our long-held belief that commercial
        quantities of D-3 oil reserves remained trapped in an attic position within
        the reef above production that exists from original, 1950s-vintage
        vertical wells.                                                                                                 

20

---





|                             | • | During
        the initial eight-hour production test of the 06-25 well, it flowed at
        anaverage rate of 990 boe/d and averaged 498 boe/d
        in 61 operating days.                                                                                                                                      
|---------------------------- | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                             | • | We drilled
        a successful Ostracod A natural gas well at 07-26.                                                                                                                                                                                                                                               
|                             | • | We drilled
        a successful well targeting crude oil in the Nisku (D-2) formation at
        12-25. An oil well re-completion was successful
        in the Wabamun(D-1) formation at 10-36.                                                                                                                    
|                             | • | Drilling
        and completion activity increased the production of oil and natural gasliquids during Nine-Month Fiscal Transition 2002
        by an average of 259 boe/d or37%, to 959 boe/d
        over Fiscal 2002.                                                                                           
|                             | • | Natural gas
        production declined during Nine-Month Fiscal Transition 2002 by anaverage
        of 124 boe/d or 6%, to 1,893 boe/d over Fiscal 2002, in response to anexpected decline in reservoir pressure.                                                                                                 
|                             | • | In total,
        we increased our average daily production rates at St. Albert in Nine-Month
        Fiscal Transition 2002 by a net of 135 boe/d or 5%, to 3,852 boe/d over
        theprevious twelve-month period to a daily average
        of 2,852 boe/d.                                                    
|                             | • | Overall,
        reserves and production at St. Albert were added while minimizingsurface
        and environmental impact by re-entering existing well bores and surfacefacilities.                                                                                                                                
|                             |   |                                                                                                                                                                                                                                                                                                                     
|Looking
      ahead to 2003  | • | We have identified
        several drilling targets prospective for incremental crude oiland
        natural gas recovery.                                                                                                                                                                                          
|                             | • | We have budgeted
        eight new wells at St. Albert in 2003, six targeting remainingcrude
        oil potential in established pools and two targeting accelerated natural
        gasproduction from the Ostracod A pool.                                                                                       
|                             | • | We plan to
        address declining reservoir pressures in various natural gas pools byadding third-party compression at the inlet to processing
        facilities located atVillenueve and Carbondale
        gas plants.                                                                                        
|                             |   |                                                                                                                                                                                                                                                                                                                     
|Halkirk                      | • | Halkirk is
        in central Alberta approximately 168 kilometers (kms) northeast ofCalgary.                                                                                                                                                                                                                       
|                             |   |                                                                                                                                                                                                                                                                                                                     
|Geological
      description | • | This area
        is prospective for multiple, sweet natural gas-bearing Cretaceous-agedsandstone reservoirs.                                                                                                                                                                                                       
|                             | • | The primary
        target for reserves is the Viking C sand with an average net
        paythickness of approximately five meters.                                                                                                                                                                               
|                             |   |                                                                                                                                                                                                                                                                                                                     
|Land
      holdings          | • | We have 7,040
        gross acres (6,638 net) under lease.                                                                                                                                                                                                                                                          
|                             |   |                                                                                                                                                                                                                                                                                                                     
|Wells
      and facilities   | • | We own a
        100% WI in four producing gas wells and onesuspended
        well.                                                                                                                                                                                                                                 
|                             | • | We also own
        an 80% WI BPO (before payout) and a 48% WI APO (after payout) in three
        producing gas wells.                                                                                                                                                                                             
|                             | • | All our natural
        gas production is processed at the Maple Glen Refrigeration Plantunder
        a third-party custom processing agreement.                                                                                                                                                                   
|                             |   |                                                                                                                                                                                                                                                                                                                     
|Operating
      activities   | • | We drilled
        one successful Viking C natural gas well at location 12-30 andsuccessfully
        re-completed a previously abandoned well bore in the Viking C sandat
        location 6-24.                                                                                                                   
|                             | • | We conducted
        several work-over operations on existing wells during Nine-MonthFiscal
        Transition 2002.                                                                                                                                                                                                
|                             | • | Production
        of natural gas and natural gas liquids decreased in Nine-Month FiscalTransition 2002 by 32 boe or 10%, to 288 boe/d on
        an operating day basis overFiscal 2002 reflecting
        an expected decrease in reservoir pressure and tightreservoir
        permeability in the Viking C sand.
|                             | • | To date,
        our reserves at Halkirk are based on a 320-acre drainage area; in thefuture we will need to drill infill wells to increase
        reserve allocations.                                                                                                                                            
|                             |   |                                                                                                                                                                                                                                                                                                                     

21

---





|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|---------------------------- | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Looking
      ahead to 2003  | •  | We expect
        to maintain current production rates by drilling two infill wells in 2003
        and adding third-party compression services at the Maple Glen gas plant.                                                                                                                                                                          
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Wimborne                     | •  | Wimborne
        is located in south-central Alberta approximately 112 kms northeast of
        Calgary.                                                                                                                                                                                                                                              
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Geological
      description | •  | This area
        is prospective for multiple Cretaceous-aged sandstone reservoirs containing
        natural gas and natural gas liquids.                                                                                                                                                                                                            
|                             | •  | Additional
        potential exists for crude oil and natural gas within deeper Mississippian
        carbonate reservoirs in the Pekisko formation.                                                                                                                                                                                                  
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Wells
      and facilities   | •  | We have not
        drilled any wells to date.                                                                                                                                                                                                                                                                                                        
|                             | •  | The property
        is in close proximity to existing natural gas pipelines and processing
        facilities.                                                                                                                                                                                                                                       
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Land
      Holdings          | •· | We own 3,200
        gross acres (3,200 net) of petroleum and natural gas (P&NG) rights.                                                                                                                                                                                                                                                              
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Operating
      activities   | •  | During the
        period, we participated in a large multi-client 3D seismic shoot and conducted
        our own 3D proprietary seismic program. In total, we shot or acquired
        over 160 kms2of high quality 3D seismic, a database that is
        expected to provide a long-term exploration and development strategy for
        the area.
|                             | •  | We acquired
        a 100% WI in one new section (640 acres) of crown P&NG lands.                                                                                                                                                                                                                                                                     
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Looking
      ahead to 2003  | •  | Since December
        31, 2002, we acquired 4,480 gross acres (4,480 net) of new crown P&NG
        leases.                                                                                                                                                                                                                                          
|                             | •  | We have identified
        through seismic up to 12 exploration and development targets on our lands,
        and plan to drill three exploration wells in 2003.                                                                                                                                                                                      
|British Columbia Properties  |    |                                                                                                                                                                                                                                                                                                                                                       
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Cypress/Chowade              | •  | Cypess/Chowade
        is located in the foothills of northern British Columbia approximately
        100 kms northwest of Fort St. John.                                                                                                                                                                                                             
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Geological
      description | •  | The area
        is prospective for multiple, natural gas-bearing Triassic sandstone and
        deep Mississippian carbonate reservoirs contained within classic foothill
        anticlines that trend northwest-southeast through the area.                                                                                                        
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Land
      holdings          | •  | We have under
        lease 15,509 gross acres (5,779 net).                                                                                                                                                                                                                                                                                           
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Wells
      and facilities   | •  | In four wells,
        we own a 50% BPO-30% APO WI and in one other well, we own a 50% WI, both
        BPO and APO.                                                                                                                                                                                                                                  
|                             | •  | A major expansion
        of pipeline and processing is required.                                                                                                                                                                                                                                                                                     
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Operating
      activities   | •  | We participated
        in drilling five exploration wells under two, separate farmin agreements
        targeting multi-zone natural gas bearing reservoirs of Triassic age. All
        five wells were cased as new-pool natural gas discoveries.                                                                                                  
|                             | •  | Initial independent
        estimates of productivity from the five wells is in excess of 20 mmcf/d
        (10 mmcf/d net to us), based on drill-stem and production testing.                                                                                                                                                                        
|                             |    |                                                                                                                                                                                                                                                                                                                                                       
|Looking
      ahead to 2003  | •  | Natural gas
        discoveries to date justify the partnership to finance a major expansion
        of existing natural gas production and transportation facilities.                                                                                                                                                                                
|                             | •  | We expect
        to have two wells on stream during the summer and three more on by late
        fall 2003.                                                                                                                                                                                                                                          
|                             | •  | We have assembled
        a large, 2D seismic database on our lands and have mapped multiple prospect
        fairways on which the land strategy was based. We have seismically identified
        more than 20 potential exploration and development locations.                                                                                     
|                             | •  | We plan to
        drill up to six outpost wells in 2003, three exploratory and three development.                                                                                                                                                                                                                                                    
|                             | •  | Since December
        31, 2002, we have acquired a total of 24,100 gross acres (7,799 net) of
        P&NG rights at two separate crown land sales. This brings our total
        land holdings to 36,609 gross acres (13,467 net).                                                                                                                  
|                             | •  | We plan to
        continue an aggressive land acquisition strategy under an expanded area
        of mutual interest with our two industry partners, encompassing approximately
        750,000 gross acres.                                                                                                                                         
|                             |    |                                                                                                                                                                                                                                                                                                                                                       

22

---





|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|---------------------------- | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Orion                        |   | Orion
        is strategically located between the Sierra and Helmet natural gas fieldsapproximately 56 kms west of the Alberta border
        and 112 kms south of the NorthwestTerritories border.
        The property is dissected by the Sierra Yoyo Desan Road, whichprovides
        year-round access for drilling operations.                                                                                                                                                                                                                                             
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Geological
      description | • | The
        area is prospective for natural gas exploration and development in the
        JeanMarie, Bluesky, Debolt and deeper Slave Point
        formations.                                                                                                                                                                                                                                                                                                                                                                                                                   
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Land
      holdings          | • | We
        hold under lease 66,405 gross acres (46,642 net).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Wells
      and facilities   | • | We
        own a 100% WI in onepotential Bluesky and onehorizontal Jean Marie natural
        gas well.                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|                             | • | In
        one horizontal Jean Marie potential natural gas well we own a 15% grossoverriding BPO and a 50% WI APO.                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|                             | • | Our
        property is located at the termination of two major pipeline systems.
        The Duke Energy Pipeline System connects to Fort Nelson for delivery to
        Washington State and the Duke Energy Field Services Pipeline System connects
        to Tooga Compressor Station for delivery to Alberta. Both pipelines are
        approximately seven kms from our property.                                                                                                                                                                                          
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Operating
      activities   | • | A
        horizontal well was drilled and completed as a potential Jean Marie natural
        gaswell. The well was drilled by our large, independent
        Canadian oil and gas partnerpursuant to a farmin
        agreement.                                                                                                                                                                                                                                                                                                                                                  
|                             | • | We
        pursued an aggressive land acquisition program by adding 36,401 gross
        acres(23,308 net) of P&NG leases. Approximately
        59% of our lands are owned byDynamic (50%) and
        its partner. We own 100% working interest in the balance.                                                                                                                                                                                                                                                                                                                  
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Looking
      ahead to 2003  | • | A
        large independent Canadian oil and gas company has used the term, TheGreater Sierra Gas Play to refer to the regional
        Jean Marie, and has described thearea as the largest
        gas play discovered in Western Canada. Our lands form a partof
        the area and are a key element in our long-term growth strategy.                                                                                                                                                                                                                                     
|                             | • | We
        plan to drill one horizontal exploration test well into the Jean Marie
        formationand shoot 90 kms2of proprietary
        3D seismic in 2003 in preparation for futuredrilling.                                                                                                                                                                                                                                                                                                                                                                                   
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Fraser Valley                |   | The
        property is located in the Lower Mainland area of southwest British Columbianear the port City of Vancouver.                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Land
      holdings          | • | Under
        a joint venture agreement with Conoco Canada Limited, we continue tohold
        approximately 54,502 gross acres (18,278 net) of onshore and offshoreP&NG rights associated with Permit 802, a validated
        British ColumbiaExploration Permit.                                                                                                                                                                                                                                                                                                                
|                             | • | Permit
        802 is under Provincial jurisdiction and includes offshore P&NG rights
        inthe Georgia Basin, located in the Strait of Georgia
        between the Lower Mainlandand Vancouver Island.                                                                                                                                                                                                                                                                                                                                                                        
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|Looking
      ahead to 2003  | • | Presently,
        areas offshore are subject to a restricted access moratorium forpetroleum
        and natural gas activities; however, discussions are underway betweenthe Provincial and Federal Governments in regards
        to lifting the moratorium. TheProvincial Government
        has indicated its desire to move forward and the FederalGovernment
        is currently conducting a public review to identify environmental andsocial concerns arising from offshore activities
        along the Pacific West Coast. Afinal decision is
        expected in 2004.
|                             | • | While
        commercial natural gas is yet to be discovered in this area, we haveidentified
        additional drill targets that are prospective for natural gas accumulation.The presence on our lands of a large structural
        feature (Roberts Bank GravityAnomaly) approximately
        19 kms2in size has been supported by governmentgravity
        and onshore seismic data.                                                                                                                                                                                      
|                             | • | The
        Geological Survey of Canada has assigned the Georgia Basin a reserveestimate
        of 6.5 trillion cubic feet of natural gas.                                                                                                                                                                                                                                                                                                                                                                                                                                        
|                             |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    

23

---





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

Reserves of Natural Gas, Natural Gas Liquids and Crude Oil

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

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

|                                   |             |   | Natural Gas |   |           |  |            | 
|---------------------------------- | ----------- | - | ----------- | - | --------- |  | ---------- | 
|                                   | Natural Gas |   | Liquids     |   | Crude Oil |  | Equivalent | 
|                                   | (mmcf)      |   | (mbbls)     |   | (mbbls)   |  | (mboe)     | 
|                                   |             |   |             |   |           |  |            | 
|Proved producing                   | 19,690      |   | 1,122       |   | 667       |  | 5,070      | 
|Proved non-producing               | 12,004      |   | 361         |   | 739       |  | 3,100      | 
|                                   |             |   |             |   |           |  |            | 
|Total proved (P)                   | 31,694      |   | 1,483       |   | 1,406     |  | 8,170      | 
|Probable additional (PA)           | 11,591      |   | 296         |   | 883       |  | 3,111      | 
|                                   |             |   |             |   |           |  |            | 
|Total P+PA as of December 31, 2002 | 43,285      |   | 1,779       |   | 2,288     |  | 11,281     | 
|Total P+PA as of March 31, 2002    | 44,740      |   | 1,905       |   | 553       |  | 9,915      | 
|                                   |             |   |             |   |           |  |            | 
|Increase (decrease)                | (1,455      | ) | (126        | ) | 1,735     |  | 1,366      | 
|Increase (decrease) %              | (3.3)%      |   | (6.6)%      |   | 313.7%    |  | 13.8%      | 
|                                   |             |   |             |   |           |  |            | 

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

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

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

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

|                                          |             |   | Natural Gas |   |           |   |            |  
|----------------------------------------- | ----------- | - | ----------- | - | --------- | - | ---------- | -
|                                          | Natural Gas |   | Liquids     |   | Crude Oil |   | Equivalent |  
|                                          | (mmcf)      |   | (mbbls)     |   | (mbbls)   |   | (mboe)     |  
|                                          |             |   |             |   |           |   |            |  
|Opening reserves as at March 31, 2002     | 44,740      |   | 1,905       |   | 553       |   | 9,915      |  
|Acquisitions                              | 588         |   | 18          |   | -         |   | 116        |  
|Revision of previous estimates            | (10,444     | ) | 18          |   | 1,180     |   | (544       | )
|Production                                | (3,898      | ) | (192        | ) | (75       | ) | (916       | )
|Extensions and discoveries                | 12,299      |   | 30          |   | 630       |   | 2,710      |  
|                                          |             |   |             |   |           |   |            |  
|Year-end reserves as at December 31, 2002 | 43,285      |   | 1,779       |   | 2,288     |   | 11,281     |  
|                                          |             |   |             |   |           |   |            |  

24

---







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

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

Discounted net present value 
  (Before taxes, after royalties)

|($ 000s)                          | 0%      |  | 10%     |  | 15%     | 
|---------------------------------- | ------- |  | ------- |  | ------- | 
|                                   |         |  |         |  |         | 
|Proved producing                   | 106,503 |  | 74,117  |  | 65,512  | 
|Proved non-producing               | 58,241  |  | 35,534  |  | 29,469  | 
|                                   |         |  |         |  |         | 
|Total proved (P)                   | 164,744 |  | 109,651 |  | 94,981  | 
|Probable additional (PA)           | 62,787  |  | 33,775  |  | 27,339  | 
|                                   |         |  |         |  |         | 
|Total P+PA as at December 31, 2002 | 227,531 |  | 143,426 |  | 122,320 | 
|Total P+PA as at March 31, 2002    | 116,510 |  | 76,526  |  | 65,239  | 
|                                   |         |  |         |  |         | 
|Increase (decrease)                | 111,021 |  | 66,900  |  | 57,081  | 
|Increase (decrease) %              | 95.3%   |  | 87.4%   |  | 87.5%   | 
|                                   |         |  |         |  |         | 

Reserve Life Indices

|                                      | Nine-Month Period Ended |  | Twelve-Month       |  |                     | 
|------------------------------------- | ----------------------- |  | ------------------ |  | ------------------- | 
|                                      | Dec 31, 2002            |  | Period             |  | Twelve-Month Period | 
|                                      | Annualized 1            |  | Ended Mar 31, 2002 |  | Ended Mar 31, 2001  | 
|                                      |                         |  |                    |  |                     | 
|Proved (yrs)                          | 6.7                     |  | 7.5                |  | 8.4                 | 
|Proved plus probable additional (yrs) | 9.2                     |  | 8.4                |  | 9.5                 | 
|                                      |                         |  |                    |  |                     | 

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

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

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





25

---







26

---







27

---







28

---







29

---







30

---







31

---







32

---





Item 5.    Operating and Financial Review and Prospects

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

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

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

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

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

We
  wish to caution readers not to place undue reliance on any forward-looking statement
  and to recognize that the statements are predictions of future results, which
  may not occur as anticipated. Actual results could differ materially from those
  anticipated in the forward-looking statements and from historical results, due
  to the risks and uncertainties described above, as well as others not now anticipated.
  The foregoing statements are not exclusive and further information concerning
  us, including factors that potentially could materially affect our financial
  results, may emerge from time to time. We assume no obligation to update forward-looking
  statements to reflect actual results or changes in factors or assumptions affecting
  such forward-looking statements.

33

---





Operating Results

Summary

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

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

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

Drilling Activity

|             | Nine-Month Fiscal |  |             |  |             |  |      |  |       | 
|------------ | ----------------- |  | ----------- |  | ----------- |  | ---- |  | ----- | 
|             | Transition 2002   |  | Fiscal 2002 |  | Fiscal 2001 | 
|             |                   |  |             |  |             |  |      |  |       | 
|             | Gross             |  | Net         |  | Gross       |  | Net  |  | Gross | 
|Natural gas  | 7                 |  | 4.3         |  | 9           |  | 7.5  |  | 14    | 
|Crude oil    | 2                 |  | 1.5         |  | 1           |  | 0.7  |  | 1     | 
|Dry          | -                 |  | -           |  | 4           |  | 2.8  |  | 2     | 
|             |                   |  |             |  |             |  |      |  |       | 
|Total        | 9                 |  | 5.8         |  | 14          |  | 11.0 |  | 17    | 
|             |                   |  |             |  |             |  |      |  |       | 
|Success rate |                   |  | 100%        |  |             |  | 75%  |  |       | 
|             |                   |  |             |  |             |  |      |  |       | 

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

Managements
  Discussion and Analysis of Operating and Financial Results

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

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

34

---







|Highlights                                                | Nine-      |  |     |   |        |   |      |   |        |  
|--------------------------------------------------------- | ---------- |  | --- | - | ------ | - | ---- | - | ------ | -
|                                                          | Month      |  |     |   |        |   |      |   |        |  
|                                                          | Fiscal     |  |     |   |        |   |      |   |        |  
|                                                          | Transition |  | %   |   | Fiscal |   | %    |   | Fiscal |  
|($ 000s)                                                 | 2002       |  | Chg |   | 2002   |   | Chg  |   | 2001   |  
|                                                          |            |  |     |   |        |   |      |   |        |  
|Earnings                                                  | 1,978      |  | 156 |   | (3,519 | ) | (136 | ) | 9,714  |  
|Earnings per share                                        | 0.10       |  | 159 |   | (0.17  | ) | (135 | ) | 0.49   |  
|Cash flow from operations (1)                             | 10,723     |  | (5  | ) | 11,337 |   | (38  | ) | 18,168 |  
|Cash flow from operations per share (1)                   | 0.53       |  | (4  | ) | 0.55   |   | (38  | ) | 0.91   |  
|Natural gas, liquids and oil production (boe/d)
      (2) | 3,332      |  | 3   |   | 3,225  |   | 22   |   | 2,644  |  
|Capital expenditures                                      | 12,578     |  | (43 | ) | 22,111 |   | 91   |   | 11,582 |  
|Established reserve additions (mboe)                      | 1,366      |  | 84  |   | 741    |   | 247  |   | (504   | )
|Debt (3)                                                  | 16,818     |  | 27  |   | 13,281 |   | -    |   | -      |  
|Debt to cash flow (times) (4)                             | 1.6:1      |  |     |   | 1.2:1  |   |      |   | -      |  
|Debt to cash flow annualized (5)                          | 1.2:1      |  |     |   | 1.2:1  |   | -    |   |        |  
|                                                          |            |  |     |   |        |   |      |   |        |  

|(1) | Cash flow from operations
        is a non-GAAP measure that does not have standardized meaning as prescribed
        by GAAP and is therefore unlikely to be comparable to similar measures
        presented by other companies. We consider it a key measure as it demonstrates
        our ability to generate the cash flow necessary to fund future growth
        through capital investment and to repay debt. Below is the determination
        of the non-GAAP measure by utilizing existing GAAP measures.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|                                                   | Nine-      |   |      |   |        |  |     |   |             |  
|-------------------------------------------------- | ---------- | - | ---- | - | ------ |  | --- | - | ----------- | -
|                                                   | Month      |   |      |   |        |  |     |   |             |  
|                                                   | Fiscal     |   |      |   |        |  |     |   |             |  
|                                                   | Transition |   | %    |   | Fiscal |  | %   |   |             |  
|($ 000s)                                          | 2002       |   | Chg  |   | 2002   |  | Chg |   | Fiscal 2001 |  
|                                                   |            |   |      |   |        |  |     |   |             |  
|Cash flow from operating activities (GAAP measure) | 11,370     |   | 16   |   | 9,779  |  | (49 | ) | 19,264      |  
|Changes in non-cash working capital (GAAP measure) | (647       | ) | (142 | ) | 1,559  |  | 242 |   | (1,096      | )
|                                                   |            |   |      |   |        |  |     |   |             |  
|Cash flow from operations (non-GAAP measure)       | 10,723     |   | (5   | ) | 11,337 |  | (38 | ) | 18,168      |  
|                                                   |            |   |      |   |        |  |     |   |             |  

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

Cash
  Flow from Operations and Earnings

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

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

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

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

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

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

35

---





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

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

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

Revenue

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

|Revenue Variances   |       |  |        |   |        |  
|------------------- | ----- |  | ------ | - | ------ | -
|($ 000s)           | Price |  | Volume |   | Total  |  
|                    |       |  |        |   |        |  
|Natural gas         | 2,152 |  | (6,095 | ) | (3,943 | )
|Natural gas liquids | 307   |  | (737   | ) | (430   | )
|Crude oil           | 521   |  | 1,573  |   | 2,094  |  
|                    |       |  |        |   |        |  
|Total               | 2,980 |  | (5,259 | ) | (2,279 | )
|                    |       |  |        |   |        |  

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

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

|Revenue Variances   |         |   |        |  |        |  
|------------------- | ------- | - | ------ |  | ------ | -
|($ 000s)           | Price   |   | Volume |  | Total  |  
|                    |         |   |        |  |        |  
|Natural gas         | (10,851 | ) | 3,846  |  | (7,005 | )
|Natural gas liquids | (2,197  | ) | 704    |  | (1,493 | )
|Crude oil           | (111    | ) | 548    |  | 437    |  
|                    |         |   |        |  |        |  
|Total               | (13,159 | ) | 5,098  |  | (8,061 | )
|                    |         |   |        |  |        |  

Daily Average Production Rates and Annual Production

|                             | Nine-Month Fiscal |  | %   |   |             |  | %   |   |             | 
|---------------------------- | ----------------- |  | --- | - | ----------- |  | --- | - | ----------- | 
|                             | Transition 2002   |  | chg |   | Fiscal 2002 |  | chg |   | Fiscal 2001 | 
|                             |                   |  |     |   |             |  |     |   |             | 
|Natural gas (mcf/d)          | 14,174            |  | (6  | ) | 15,107      |  | 21  |   | 12,486      | 
|Natural gas liquids (bbl/d)  | 698               |  | 11  |   | 631         |  | 19  |   | 530         | 
|Crude oil (bbl/d)            | 271               |  | 257 |   | 76          |  | 130 |   | 33          | 
|Equivalent (boe/d)           | 3,332             |  | 3   |   | 3,225       |  | 22  |   | 2,644       | 
|Total production (mboe)      | 916               |  | (22 | ) | 1,177       |  | 22  |   | 965         | 
|Gas weighting (%)            | 71                |  | (9  | ) | 78          |  | (1  | ) | 79          | 
|Annualized production (mboe) | 1,221             |  | 4   |   | 1,177       |  | 22  |   | 965         | 
|                             |                   |  |     |   |             |  |     |   |             | 

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

36

---





Corporate
  Production

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

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

---

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

St. Albert, Alberta

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

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

---

Halkirk, Alberta

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

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



---

Peavey/Morinville, Alberta

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

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



---

37

---





Cypress/Chowade, NE British Columbia

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

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

---

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

Weighted Average Commodity Prices

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

|                            | Nine-Month Fiscal |  | %   |  |             |  | %   |   |             | 
|--------------------------- | ----------------- |  | --- |  | ----------- |  | --- | - | ----------- | 
|                            | Transition 2002   |  | chg |  | Fiscal 2002 |  | chg |   | Fiscal 2001 | 
|                            |                   |  |     |  |             |  |     |   |             | 
|Natural gas ( $/mcf)        | 4.36              |  | 14  |  | 3.81        |  | (39 | ) | 6.22        | 
|Natural gas liquids ($/bbl) | 20.90             |  | 8   |  | 19.30       |  | (37 | ) | 30.64       | 
|Crude oil ($/bbl)           | 41.40             |  | 21  |  | 34.33       |  | (21 | ) | 43.60       | 
|                            |                   |  |     |  |             |  |     |   |             | 

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

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

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

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



38

---





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

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

|                                   | Nine-Month Fiscal |   | %   |   |             |   | %   |   |             |  
|---------------------------------- | ----------------- | - | --- | - | ----------- | - | --- | - | ----------- | -
|($ 000s, unless otherwise stated) | Transition 2002   |   | chg |   | Fiscal 2002 |   | chg |   | Fiscal 2001 |  
|                                   |                   |   |     |   |             |   |     |   |             |  
|Crown                              | 1,252             |   | (5  | ) | 1,317       |   | (55 | ) | 2,958       |  
|Freehold and overriding            | 3,327             |   | (18 | ) | 4,067       |   | (37 | ) | 6,106       |  
|Freehold mineral taxes (1)         | 943               |   | (16 | ) | 1,116       |   | 41  |   | 794         |  
|ARTC                               | (178              | ) | 12  |   | (159        | ) | 68  |   | (499        | )
|                                   |                   |   |     |   |             |   |     |   |             |  
|Total                              | 5,344             |   | (16 | ) | 6,341       |   | (32 | ) | 9,359       |  
|Per boe ($)                        | 5.83              |   | 8   |   | 5.39        |   | (44 | ) | 9.70        |  
|                                   |                   |   |     |   |             |   |     |   |             |  

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

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

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

Production Costs

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

|                                   | Nine-Month Fiscal |  | %   |   | Fiscal 2002 |  | %   |   | Fiscal 2001 | 
|---------------------------------- | ----------------- |  | --- | - | ----------- |  | --- | - | ----------- | 
|($ 000s, unless otherwise stated) | Transition 2002   |  | chg |   |             |  | chg |   |             | 
|                                   |                   |  |     |   |             |  |     |   |             | 
|Production costs (1)- total        | 5,470             |  | (6  | ) | 5,846       |  | (55 | ) | 4,580       | 
|Per boe ($)                        | 5.97              |  | 20  |   | 4.97        |  | 5   |   | 4.75        | 
|                                   |                   |  |     |   |             |  |     |   |             | 

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

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

| | • | An increase of $0.33 per boe from higher electricity costs at St. Albert;                                                                                              
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | An increase of $0.22 per boe from plant
        and battery maintenance costs at St. Albert not conducted in Fiscal 2002.                                              
| | • | An increase of $0.45 per boe was due to increases in field compression
      charges and well maintenance costs.                                                       
| |   |                                                                                                                                                                        
| |   | In 2003, we expect unit production costs to change from current levels
          by:                                                                                   
| |   |                                                                                                                                                                        
| | • | A decrease of $0.51 per boe due to the elimination
        of monthly sales and leaseback charges at St. Albert (see Note 5 to our
        Financial Statements);      
| | • | A savings of $0.22 per boe, as the gas plant and
        oil battery maintenance costs performed in Nine-Month Fiscal Transition
        2002 will not be required; and



39

---







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

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

Amortization and Depletion Expenses (A&D)

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

|                                   | Nine-Month Fiscal |   | %   |   |             |   | %   |  |             |  
|---------------------------------- | ----------------- | - | --- | - | ----------- | - | --- |  | ----------- | -
|($ 000s, unless otherwise stated) | Transition 2002   |   | chg |   | Fiscal 2002 |   | chg |  | Fiscal 2001 |  
|                                   |                   |   |     |   |             |   |     |  |             |  
|A&D before the following:          | 5,924             |   | 11  |   | 5,336       |   | 72  |  | 3,097       |  
|- Ceiling test adjustment          | 445               |   | (93 | ) | 6,783       |   | -   |  | 36          |  
|- Future removal and               |                   |   |     |   |             |   |     |  |             |  
|site restoration
      provision   | 167               |   | (41 | ) | 284         |   | 54  |  | 185         |  
|- Amortization of                  |                   |   |     |   |             |   |     |  |             |  
|deferred
      Items               | (109              | ) | 53  |   | (230        | ) | 26  |  | (311        | )
|                                   |                   |   |     |   |             |   |     |  |             |  
|Total A&D                          | 6,427             |   | (47 | ) | 12,173      |   | 305 |  | 3,007       |  
|Per boe ($)                        | 7.02              |   | (32 | ) | 10.34       |   | 231 |  | 3.12        |  
|                                   |                   |   |     |   |             |   |     |  |             |  

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

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

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

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

Exploration Expenses

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

|                                   | Nine-Month Fiscal |  | %   |   |             |  | %   |   |             | 
|---------------------------------- | ----------------- |  | --- | - | ----------- |  | --- | - | ----------- | 
|($ 000s, unless otherwise stated) | Transition 2002   |  | chg |   | Fiscal 2002 |  | chg |   | Fiscal 2001 | 
|                                   |                   |  |     |   |             |  |     |   |             | 
|Drilling                           | 325               |  | (91 | ) | 3,821       |  | 472 |   | 668         | 
|Seismic data activity              | 847               |  | 31  |   | 649         |  | (41 | ) | 1,102       | 
|Other                              | 187               |  | 6   |   | 176         |  | 14  |   | 153         | 
|                                   |                   |  |     |   |             |  |     |   |             | 
|Total                              | 1,359             |  | (71 | ) | 4,646       |  | 142 |   | 1,923       | 
|Per boe ($)                        | 1.48              |  | (63 | ) | 3.95        |  | 98  |   | 1.99        | 
|                                   |                   |  |     |   |             |  |     |   |             | 

40

---





Nine-Month
  Fiscal Transition 2002 vs Fiscal 2002


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

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

Fiscal
  2002 vs Fiscal 2001


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

Gain on Sale of Natural Gas and Oil Interests

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

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

Interest Expense and Interest Income (Net Interest)

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

|                                   | Nine-Month Fiscal |   | %   |   |             |   | %   |   |             |  
|---------------------------------- | ----------------- | - | --- | - | ----------- | - | --- | - | ----------- | -
|($ 000s, unless otherwise stated) | Transition 2002   |   | chg |   | Fiscal 2002 |   | chg |   | Fiscal 2001 |  
|                                   |                   |   |     |   |             |   |     |   |             |  
|Interest expense                   | 454               |   | (8  | ) | 494         |   | 106 |   | 240         |  
|Interest income                    | (2                | ) | (91 | ) | (22         | ) | (12 | ) | (25         | )
|                                   |                   |   |     |   |             |   |     |   |             |  
|Interest expense - net             | 452               |   | (4  | ) | 472         |   | 120 |   | 215         |  
|Per boe ($)                        | 0.49              |   | 23  |   | 0.40        |   | 82  |   | 0.22        |  
|                                   |                   |   |     |   |             |   |     |   |             |  

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

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

General and Administrative Expenses (G&A)

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

|                                   | Nine-Month Fiscal |  | %   |   |             |  | %   |  |             | 
|---------------------------------- | ----------------- |  | --- | - | ----------- |  | --- |  | ----------- | 
|($ 000s, unless otherwise stated) | Transition 2002   |  | chg |   | Fiscal 2002 |  | chg |  | Fiscal 2001 | 
|                                   |                   |  |     |   |             |  |     |  |             | 
|General & administrative           | 1,926             |  | (18 | ) | 2,347       |  | 50  |  | 1,569       | 
|Per boe ($)                        | 2.10              |  | 6   |   | 1.99        |  | 22  |  | 1.63        | 
|                                   |                   |  |     |   |             |  |     |  |             | 

41

---





Nine-Month
  Fiscal Transition 2002 vs Fiscal 2002


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

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

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

Income Taxes

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

|                   | Nine-Month Fiscal |  | %   |  |             |   | %    |   |             | 
|------------------ | ----------------- |  | --- |  | ----------- | - | ---- | - | ----------- | 
|$(000s)           | Transition 2002   |  | chg |  | Fiscal 2002 |   | chg  |   | Fiscal 2001 | 
|                   |                   |  |     |  |             |   |      |   |             | 
|Income tax expense |                   |  |     |  |             |   |      |   |             | 
|- Current          | 207               |  | 257 |  | 58          |   | (90  | ) | 572         | 
|- Future           | 961               |  | 149 |  | (1958       | ) | (147 | ) | 4,163       | 
|                   |                   |  |     |  |             |   |      |   |             | 
|Total              | 1,168             |  | 161 |  | (1,900      | ) | (140 | ) | 4,735       | 
|                   |                   |  |     |  |             |   |      |   |             | 

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

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

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

Income Tax Pools Available for Deduction Against Future
  Taxable Income

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

|                             | Nine-Month Fiscal |  |             |  |             |  | Maximum Annual | 
|---------------------------- | ----------------- |  | ----------- |  | ----------- |  | -------------- | 
|$(000s)                     | Transition 2002   |  | Fiscal 2002 |  | Fiscal 2001 |  | Deduction      | 
|                             |                   |  |             |  |             |  |                | 
|Cdn exploration expense      | 1,586             |  | -           |  | -           |  | 100%           | 
|Non-capital losses           | -                 |  | -           |  | -           |  | 100%           | 
|Share issue costs            | -                 |  | -           |  | -           |  | 100%           | 
|Cdn development expense      | 5,246             |  | 3,772       |  | 3,307       |  | 30%            | 
|Undepreciated capital costs  | 10,356            |  | 10,297      |  | 5,554       |  | 20% - 100%     | 
|Cdn oil/gas property expense | 17,417            |  | 16,471      |  | 3,986       |  | 10%            | 
|                             |                   |  |             |  |             |  |                | 
|Total                        | 34,605            |  | 30,540      |  | 12,847      |  |                | 
|                             |                   |  |             |  |             |  |                | 

42

---





Commitments

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

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

Critical Accounting Policies

Our
  critical accounting policies are defined as those that are important both to
  the portrayal of our financial position and operations and require us to make
  judgments based on underlying estimates and assumptions about future events
  and their effects. Such underlying estimates and assumptions are based on historical
  experience and other factors that we believe to be reasonable under the circumstances.
  These estimates and assumptions are subject to change as new events occur, as
  more industry experience is acquired, as additional information is obtained
  and as our operating environment changes. We believe the following are the most
  critical areas where estimates and our accounting policies can materially impact
  our financial statements. For information concerning our other significant accounting
  policies (see Note 2 to our Financial Statements under Item 17 in this Transition
  Report).

Reserves
  Estimates- On an annual basis, we engage independent petroleum consultants
  to conduct evaluations of our natural gas, natural gas liquids and crude oil
  reserves. The accuracy of reserves estimates is a matter of interpretation and
  judgment and is a function of the quality and quantity of available data gathered
  over time. For further details and a discussion of the risks involved in the
  reserves estimating process, see, BUSINESS RISK MANAGEMENT, Estimating
  of Reserves and Future Net Cash Flows Risk.

Natural
  Gas and Crude Oil Interests- We follow the successful efforts method of
  accounting for our natural gas and crude oil activities, as described in Note
  1 to our Financial Statements under Item 17 in this Transition Report. The application
  of this method requires us to make significant judgments and decisions based
  on available geological, geophysical, engineering and economic data. The results
  from drilling can take considerable time to analyze and when it is determined
  that drilling has been unsuccessful in establishing commercial reserves, the
  costs of drilling are written off immediately and reported as exploration expense.
  Drilling costs for wells that have been successful in establishing commercial
  reserves are capitalized as natural gas and oil interests on our balance sheet.

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

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

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

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

Recently Issued Accounting Standard

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

43

---





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

Inflation

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

Impact
  of Foreign Currency Fluctuations

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

Government
  Policies

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

Liquidity and Capital Resources

Liquidity

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

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

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

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

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

Financial
  Instruments

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

Substantially
  all of our accounts receivable at December 31, 2002 and March 31, 2002 resulted
  from the sale of natural gas, natural gas liquids and crude oil to other companies
  in the oil and gas industry. This concentration of customer type may impact
  our overall credit risk, either positively or negatively, in that such entities
  may be similarly

44

---





affected by industry-wide changes in economic or other conditions.
  Historically to date, we have not incurred credit losses against our receivables.
  At December 31, 2002, five customers represented 56% of our accounts receivable
  balance.

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

Outlook for 2003

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

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

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

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

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

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

Sensitivity
  Analysis

The
  following table shows the effect on cash flow of certain changes in volume,
  price and interest rates. Numbers presented reflect the sensitivity impact on
  our estimated 2003 activity.

|                  |                                 | Changes in |   |       |   |      |     | Effect on Cash Flow |      
|----------------- | ------------------------------- | ---------- | - | ----- | - | ---- | --- | ------------------- | -----
|                  |                                 |            |   |       |   |      |     |                     |      
|                  |                                 | Volume     |   | Price |   | Rate |     | ($000s)            |      
|                  |                                 |            |   |       |   |      |     |                     |      
|Production        |  natural gas (mcf/d)           | 1,000      |   | -     |   | -    |     | 1,430               |      
|                  | - natural gas liquids (bbls/d)) | 100        |   | -     |   | -    |     | 570                 |      
|                  | - crude oil (bbls/d)            | 100        |   | -     |   | -    |     | 758                 |      
|Price             | - natural gas ($/mcf)           | -          |   | 0.50  |   | -    |     | 2,136               |      
|                  | - natural gas liquids ($/bbl)   | -          |   | 1.00  |   | -    |     | 232                 |      
|                  | - crude oil ($/bbl)             | -          |   | 1.00  |   | -    |     | 319                 |      
|Interest rate (%) | -                               |            | - |       | 1 |      | 150 |                     | 0.007
|                  |                                 |            |   |       |   |      |     |                     |      

Contractual
  Obligations

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

|                                            |       |  | Payments Due by Period |  |       | 
|------------------------------------------- | ----- |  | ---------------------- |  | ----- | 
|                                            |       |  | Less than              |  | 1 - 3 | 
|$(000s)                                    | Total |  | 1 year                 |  | years | 
|                                            |       |  |                        |  |       | 
|Operating lease obligations (office space)  | 79    |  | 73                     |  | 6     | 
|Long-term debt, capital lease, purchase and |       |  |                        |  |       | 
|other long-term obligations                 | nil   |  | nil                    |  | nil   | 
|                                            |       |  |                        |  |       | 

45

---







Item 6.    Directors, Senior Management and Employees

Directors and Senior Management

The
  following is information regarding our Directors, Senior Management and Employees
  as of December 31, 2002.

|Name                              | Position Held                  | Age | Residence      
|--------------------------------- | ------------------------------ | --- | ---------------
|                                  |                                |     |                
|Directors and Executive Officers: |                                |     |                
|Wayne J. Babcock                  | President & CEO, Director      | 59  | Vancouver, B.C.
|Donald K. Umbach                  | Vice President & COO, Director | 49  | Vancouver, B.C.
|John A. Greig                     | Director                       | 61  | Vancouver, B.C.
|Jonathan A. Rubenstein            | Director                       | 53  | Vancouver, B.C.
|David J. Jennings                 | Director                       | 39  | Vancouver, B.C.
|John Lagadin                      | Director                       | 65  | Calgary, Alta. 
|William B. Thompson               | Director                       | 58  | Kelowna, B.C.  
|Michael A. Bardell                | CFO & Corporate Secretary      | 56  | Vancouver, B.C.
|David G. Grohs                    | Vice President, Production     | 37  | Vancouver, B.C.
|James R. Britton                  | Vice President, Exploration    | 68  | Vancouver, B.C.
|                                  |                                |     |                

|Wayne J. BabcockPresident, Chief
      Executive Officer,
      Director |  | 
|------------------------------------------------------------------------ |  | 

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

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

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

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

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

Mr.
  Umbach holds diplomas in Business Administration & Petroleum Land Management
  from the Mount Royal College of Calgary, Alberta and is a member of the Canadian
  Association of Petroleum Landmen. He has over 20 years experience in the Canadian
  oil and gas industry, beginning with Hudson's Bay Oil & Gas Limited, followed
  by a time with a junior oil and gas company. Prior to his joining us in 1987,
  Mr. Umbach was principle of his own Petroleum Landman consulting firm. Mr. Umbach
  is a director of ours and is Vice President and Chief Operating Officer and
  has been such since 1999.

46

---







|John A. Greig Director |  | 
|---------------------- |  | 

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

Mr.
  Greig has been a director of ours since 1990 and is presently director and chairman
  of Cumberland Resources Ltd. He is also director of Redcorp Ventures Ltd, First
  Step Ventures Ltd., Blackstone Ventures Inc. Eurozinc Mining Corp., and Diamondex
  Resources Ltd.

|Jonathan A.
      Rubenstein Director |  | 
|------------------------------------- |  | 

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

Since
  1994, he worked in senior positions with international mining companies based
  in Vancouver.

Mr.
  Rubenstein has been a director of us since July 1990.

Mr.
  Rubenstein is a director of the following public companies: Redcorp Ventures
  Ltd., Cumberland Resources, Canico Resource Corp. and Commander Resources Ltd.

|David J.
      Jennings Director |  | 
|-------------------------------- |  | 

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

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

Mr.
  Jennings was the past Chair of the Securities Subsection of the Canadian Bar
  Association, British Columbia branch, a past member of the Vancouver Stock Exchange
  Advisory Committee, and a member of the British Columbia Securities Commission
  Law Advisory Committee. Mr. Jennings has written articles and lectured on the
  areas of corporate and securities law and venture capital financing. Mr. Jennings
  has been a director of ours since August, 1999.

47

---





|John Lagadin Director |  | 
|--------------------- |  | 

Mr.
  Lagadin's list of achievements includes: founder of the C$5.5 billion Alliance
  Natural Gas Pipeline; founder and president of Direct Energy Marketing Limited,
  which grew to be the largest independent gas marketer in Canada; co-founder
  and financier of Municipal Gas Corporation, an aggregator of residential and
  commercial gas customers; founder of Energy Exchange Inc., the first commodity-styled,
  web-based electronic exchange for the sale and purchase of natural gas; and
  most recently investor and President of GeoScope Exploration Technologies, Inc.,
  a company using proprietary, state-of-the-art seismic interpretation techniques
  to explore for oil & gas.

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

Mr.
  Lagadin holds a Bachelor of Science degree in Geological Engineering from Michigan
  Technology University. Recently, he was awarded the Centennial Leadership Award
  by the Association of Professional Engineers, Geologists and Geophysicists of
  Alberta, in recognition of his achievements in the natural gas industry. He
  is currently an independent businessman.

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

|William B.
      Thompson 
      Director |  | 
|----------------------------------------- |  | 

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

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

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

48

---







|Michael A.Bardell Chief
      Financial
      Officer, Corporate
      Secretary |  | 
|-------------------------------------------------------------------------------- |  | 

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

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

Mr.
  Bardell was our controller from 1988 to 1999 and our Chief Financial Officer
  from 1999 to present.

|David G. Grohs Vice-President,
      Production |  | 
|----------------------------------------------- |  | 

Mr.
  Grohs holds a Bachelor of Applied Science degree in Mechanical Engineering from
  the University of British Columbia and is a registered professional engineer
  in the provinces of British Columbia and Alberta. He has 14 years experience
  in the Canadian oil and gas industry, including positions with Shell Canada
  Limited, Numac Energy Inc., and ENCO Gas, Ltd. David Grohs is responsible for
  production operations, engineering and acquisitions.

|James R.Britton Vice President,
      Exploration |  | 
|------------------------------------------------- |  | 

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

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

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

49

---





Compensation

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

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

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

Named Executive Officers

|Name/Position             | Salary (1) | Bonus  | Other Annual
      Compensation (2) | Options
      Granted(#) (3) | Exercise
      Price | Expiry Date
|------------------------- | ---------- | ------ | ----------------------------------- | ---------------------------- | -------------------- | -----------
|                          |            |        |                                     |                              |                      |            
|Wayne J. Babcock          |            |        |                                     |                              |                      |            
|President & CEO           | 85,210     | Nil    | 199,738                             | Nil                          | n/a                  | n/a        
|Donald K. Umbach          |            |        |                                     |                              |                      |            
|Vice President & COO      | 85,210     | Nil    | 199,738                             | Nil                          | n/a                  | n/a        
|David G. Grohs,           |            |        |                                     |                              |                      |            
|Vice-Pres, Production     | 102,701    | 20,250 | Nil                                 | Nil                          | n/a                  | n/a        
|Michael A. Bardell,       |            |        |                                     |                              |                      |            
|CFO & Corporate Secretary | 74,275     | 30,500 | Nil                                 | Nil                          | n/a                  | n/a        
|James R. Britton          |            |        |                                     |                              |                      |            
|Vice-Pres., Exploration   | 54,774     | Nil    | 199,738                             | Nil                          | n/a                  | n/a        
|                          |            |        |                                     |                              |                      |            

|(1 | ) | We changed
        our financial year end from March 31 to December 31 effective December
        31, 2002. As a result, the transition year from the old financial year
        to the new financial year is Nine-Month Fiscal Transition 2002. Salary
        amounts shown in the table above cover the nine-months of Nine-Month Fiscal
        Transition 2002 rather than a twelve-month period.                                                                                                                                                                                                          
|-- | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(2 | ) | The other
        annual compensation paid is in respect of payments to each of three Named
        Executive Officers pursuant to management royalty agreements. We pay an
        overriding royalty interest of 1% of our share of gross monthly production
        of all petroleum substances produced or deemed to be produced and marketed
        from or allocated to each well on all lands acquired by us since June
        1, 1986 (for two Named Executive Officers) and June 1, 1987 (for the third
        Named Executive Officer). See Note (1)above for period covered
        by compensation.
|   |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|(3 | ) | We have a
        formalized stock option plan for the discretionary granting of incentive
        stock options to the Named Executive Officers. No grants of stock options
        were made during Nine-Month Fiscal Transition 2002 to any of the Named
        Executive Officers.                                                                                                                                                                                                                                                                                                                           

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

As
  of July 13, 1990, we had overriding management royalty agreements with Wayne
  J. Babcock and Donald K. Umbach and as of August 31, 1990, we had an overriding
  management royalty agreement with James R. Britton. Each of the overriding management
  royalty agreements requires us to pay an overriding royalty interest of 1% of
  our share of gross monthly production of all petroleum substances produced or
  deemed to be produced and marketed from or allocated to each well on all lands
  acquired by us since June 1, 1986 for Mr. Babcock and Mr. Umbach and since June
  1, 1987 for Mr. Britton.

As
  of our most recently completed fiscal year, we had employment contracts with
  all of the Named Executive Officers. Each of the contracts has standard employment
  provisions, including salary, benefits, vacation time, non-competition and confidentiality
  provisions. In addition, each of the contracts requires the Named Executive
  Officer not to voluntarily leave his employ during actions taken by third parties
  to acquire control of us. If a Named Executive Officer resigns within six months
  of a change of control of us for the sole reason that a change of control of
  us has occurred, the Named Executive Officer may receive a severance package
  including an amount equal to 12 months salary and the

50

---





economic benefit of any stock options then outstanding. If
  the Named Executive Officer is terminated by us without cause, such officer
  may receive a severance package including an amount equal to 24 months
  salary, the economic benefit of any stock options then outstanding, and certain
  health and insurance benefits for a period not to exceed 12 months.

Other
  than the overriding royalty agreements and employment contracts described above,
  we had as of the end of the Nine-Month Fiscal Transition 2002 no compensatory
  plan or arrangement in respect of compensation received or that may be received
  by the Named Executive Officers to compensate Named Executive Officers in the
  event of the termination of employment (resignation, retirement, change of control)
  or in the event of a change in responsibilities following a change in control,
  where in respect of the Named Executive Officer the value of such compensation
  exceeds $100,000.

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

Compensation of Non-Employee Directors

|                        |            |       | Other Annual | Options         | Exercise |            
|----------------------- | ---------- | ----- | ------------ | --------------- | -------- | -----------
|Name/Position           | Salary (1) | Bonus | Compensation | Granted (#) (2) | Price    | Expiry Date
|                        |            |       |              |                 |          |            
|John A. Greig           |            |       |              | 17,500          | $1.65    | 29-Apr-2012
|Director                | Nil        | Nil   | Nil          | 15,000          | $1.75    | 21-Aug-2012
|Jonathan A. Rubenstein  |            |       |              | 17,500          | $1.65    | 29-Apr-2012
|Director                | Nil        | Nil   | Nil          | 15,000          | $1.75    | 21-Aug-2012
|David J. Jennings(3)    |            |       |              | 17,500          | $1.65    | 29-Apr-2012
|Director                | Nil        | Nil   | Nil          | 15,000          | $1.75    | 21-Aug-2012
|John Lagadin            |            |       |              | 5,000           | $1.65    | 29-Apr-2012
|Director                | Nil        | Nil   | Nil          | 15,000          | $1.75    | 21-Aug-2012
|William B. Thompson (4) |            |       |              |                 |          |            
|Director                | Nil        | Nil   | Nil          | 15,000          | $2.95    | 16-Dec-2012
|                        |            |       |              |                 |          |            

|(1) | During Nine-Month Fiscal Transition
      2002 , we did not pay any cash compensation to our directors (employee and
      non-employee), in their capacities as such.                                                                                                                                                                                                                                                                                                                  
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(2) | We have a formalized stock option
      plan for the non-discretionary, annual granting of incentive stock options
      to outside directors. The options indicated above were granted pursuant
      to that plan.                                                                                                                                                                                                                                                                    
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(3) | At our Annual General Meeting
      held on August 25, 1999, our shareholders approved the nomination of David
      J. Jennings for election as director for a three-year term. Mr. Jennings
      performs legal work on our behalf as a Barrister and Solicitor with the
      firm of Irwin, White & Jennings (1999). He was formerly a Partner in
      the firm of DuMoulin Black (1995-99). Mr. Jennings Nine-Month Fiscal
      Transition 2002 legal fees amounted to $26,625.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|(4) | Mr. Thompson was appointed as
      a director through board nomination on December 17, 2002.                                                                                                                                                                                                                                                                                                                                                                                           

Non-Cash
  Compensation to Directors, Officers and Employees

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

51

---





The
  following table shows the number of shares of common stock subject to outstanding
  stock options held by our directors or officers, as a group as of May 5, 2003.

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

|                   |                | Number of Shares of | 
|------------------ | -------------- | ------------------- | 
|Expiry Date        | Exercise Price | Common Stock        | 
|                   |                |                     | 
|January 23, 2005   | $1.45          | 25,000              | 
|September 28, 2005 | $2.10          | 300,000             | 
|April 3, 2006      | $1.70          | 80,000              | 
|February 28, 2007  | $1.75          | 210,000             | 
|August 16, 2010    | $1.72          | 112,500             | 
|September 28, 2010 | $2.10          | 18,750              | 
|April 29, 2011     | $2.15          | 52,500              | 
|August 22, 2011    | $2.10          | 60,000              | 
|April 29, 2012     | $1.65          | 57,500              | 
|August 21, 2012    | $1.75          | 60,000              | 
|December 16, 2012  | $2.95          | 15,000              | 
|April 2, 2013      | $3.91          | 12,500              | 
|April 29, 2013     | $4.10          | 65,000              | 
|                   |                |                     | 
|Total              |                | 1,068,750           | 
|                   |                |                     | 

The
  following table shows the number of shares of common stock subject to outstanding
  stock options held by employees and consultants who are neither our directors
  nor officers as of May 5, 2003.

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

|                  |                | Number of Shares of | 
|----------------- | -------------- | ------------------- | 
|Expiry Date       | Exercise Price | Common Stock        | 
|                  |                |                     | 
|July 14, 2003     | 1.72           | 18,000              | 
|January 23, 2005  | 1.45           | 20,000              | 
|July 30, 2005     | 1.75           | 30,000              | 
|September 28,2005 | 2.10           | 48,000              | 
|February 28, 2006 | 2.17           | 21,000              | 
|April 14, 2006    | 2.25           | 60,000              | 
|February 27, 2007 | 1.75           | 92,500              | 
|October 6, 2007   | 2.05           | 10,000              | 
|December 8, 2007  | 2.46           | 5,000               | 
|March 16, 2008    | 3.80           | 30,000              | 
|                  |                |                     | 
|Total             |                | 334,500             | 
|                  |                |                     | 

Stock Options Granted to and Exercised by Named Executive Officers

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

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

52

---





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

Stock Options Held by Named Executive Officers

|                   |                                     | Dollar Value of Unexercised
      In-the-
|------------------ | ----------------------------------- | -----------------------------------------
|                   | Number of Unexercised Options/SARs | Money Options/SARs Held
      At        
|                   | Held At May 5, 2003(1)              | May 5, 2003(2)                           
|Name               | Exercisable / Unexercisable         | Exercisable / Unexercisable              
|                   |                                     |                                          
|Wayne J. Babcock   | 120,000/40,000                      | 277,000/104,000                          
|Donald K. Umbach   | 120,000/40,000                      | 277,000/104,000                          
|David G. Grohs     | 26,666/73,334                       | 70,332/193,668                           
|Michael A. Bardell | 63,333/26,667                       | 147,166/69,334                           
|James R. Britton   | 60,000/20,000                       | 138,500/52,000                           
|                   |                                     |                                          

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

Board Practices

Term
  of Office

At
  our annual general meeting held on August 27, 1998, our shareholders approved
  amending our Articles to provide that approximately one-third of the members
  of the Board of Directors be elected annually for three-year terms. At the end
  of Nine-Month Fiscal Transition 2002, we had seven directors, one of which was
  board-appointed for the first time on December 17, 2002. The terms of all seven
  expire at the annual meetings of shareholders as follows:

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

|Name                   | Term of Office Remaining | Held Office Since
|---------------------- | ------------------------ | -----------------
|                       |                          |                  
|                       |                          |                  
|Directors:             |                          |                  
|Wayne J. Babcock       | Two years                | 1980             
|Donald K. Umbach       | Two years                | 1986             
|John A. Greig          | One year                 | 1991             
|Jonathan A. Rubenstein | One year                 | 1991             
|David J. Jennings      | Three years              | 1999             
|John Lagadin           | Three years              | 2000             
|William B. Thompson    | Partial year             | December 17, 2002
|                       |                          |                  

53

---





Committees:
  Audit, Audit Reserves, Compensation and Corporate Governance

The
  following table sets forth details relating to the composition of our Board
  Committees as of the end of Nine-Month Fiscal Transition 2002.

List of Directors, Committees and Committee Members

|                       | Full Board | Corporate  |              | Audit    |      
|---------------------- | ---------- | ---------- | ------------ | -------- | -----
|                       |            | Governance | Compensation | Reserves | Audit
|                      
|Non-Employee Directors |            |            |              |          |      
|John Greig             | x          | x          | x            |          | Chair
|Jonathan Rubenstein(1) | x          | x          | Chair        |          | x    
|David Jennings(2)      | x          | Chair      | x            |          | x    
|John Lagadin(2)        | x          |            |              | x        |      
|Bill Thompson(1)(2)    | x          |            |              |          | x    
|                       |            |            |              |          |      
|Employee Directors     |            |            |              |          |      
|Wayne Babcock          | Chair      |            |              |          |      
|Don Umbach             | x          |            |              |          |      
|                       |            |            |              |          |      

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

The
  Audit Committee is mandated to:

| | • | assist the Board of Directors in fulfilling
        its fiduciary responsibilities relating to accounting and reporting practices
        and internal controls;                     
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | review audited financial statements and
        managements discussion and analysis of operations with the auditors;                                                                
| | • | review the annual report and all interim reports with the auditors;                                                                                                                  
| | • | ensure that no restrictions are placed by management
        on the scope of the auditor's review and examination of our accounts;
        and                                       
| | • | recommend to the Board of Directors the firm of auditors
        to be nominated by the Board of Directors for appointment by the shareholders
        at the annual general meeting.

The Reserves Audit Committee is mandated to:

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

The
  Compensation Committee is mandated to consider and make recommendations to the
  Board of Directors for appropriate compensation packages for our executive officers
  and directors. The guiding philosophy of the Compensation Committee in determining
  compensation for executives has been to provide a compensation package that
  is flexible, entrepreneurial and geared towards attracting, retaining and motivating
  executive officers. The policies of the Compensation Committee encourage performance
  by executives to enhance our growth and profitability. Achievement of these
  objectives is intended to contribute to an increase in shareholder value. The
  Compensation Committee expects to accomplish this through defining the key components
  for executive officer compensation, being a base salary comparable to executive
  salaries in established peer group companies, and long-term incentives in the
  form of stock options. Short-term incentives in the form of a cash bonus could
  be paid for significant contributions to us. In combination, these elements
  are designed to recognize those activities of management that advance our short
  and long-term business objectives. The Compensation Committee meets as required,
  but not less than annually.

54

---





The
  Compensation Committee met three times during Nine-Month Fiscal Transition 2002.
  We have never provided compensation in the form of any plan providing compensation
  intended to serve as incentive for performance to occur over a period longer
  than one fiscal year and have not set aside or accrued for pensions. However,
  the shareholders previously approved royalty agreements with three Named Executive
  Officers whereby we pay an overriding royalty interest of 1% of our share of
  gross monthly production of all petroleum substances produced or deemed to be
  produced and marketed from or allocated to each well on all lands acquired by
  us.

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

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

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

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

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

Our
  Board of Directors is composed of seven directors. None of the members of the
  Audit, Audit Reserves, Compensation and Corporate Governance Committees has
  any indebtedness to us nor does any have any material interest, or have any
  associates or affiliates that have any material interest, direct or indirect,
  in any actual or proposed transaction in the last fiscal year that has materially
  affected or would materially affect us.

Employees

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

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

Share Ownership

The
  following table sets forth the Common Stock ownership of each of our directors
  and officers. All ownership shown is of record and reflects beneficial ownership
  as of May 5, 2003, and represents the number of shares of common stock beneficially
  owned, directly or indirectly, or controlled by the person listed. Unless otherwise
  indicated, such shares are held directly.

55

---





Share Ownership of Directors and Officers

|                       |                                | Number of Shares   | Percent of
|---------------------- | ------------------------------ | ------------------ | ----------
|Name                   | Position                       | of Common Stock(1) | Class     
|                       |                                |                    |           
|Wayne J. Babcock       | President & CEO, Director      | 839,893            | 4.0       
|Donald K. Umbach       | Vice President & COO, Director | 417,016            | 2.0       
|John A. Greig          | Director                       | 143,077            | 0.7       
|Jonathan A. Rubenstein | Director                       | 52,363             | 0.2       
|David J. Jennings      | Director                       | Nil                | -         
|John Lagadin           | Director                       | Nil                | -         
|William B. Thompson    | Director                       | Nil                | -         
|Michael A. Bardell     | CFO & Corporate Secretary      | 221,374            | 1.1       
|James R. Britton       | Vice President, Exploration    | 186,677            | 0.9       
|David G. Grohs         | Vice President, Operations     | 15,000             | 0.1       
|                       |                                |                    |           

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


Item 7.   Major Shareholders and Related Party Transactions Major
  Shareholders

To
  the best of our knowledge, no person beneficially owns, directly or indirectly,
  or exercises control or direction over shares constituting more than five percent
  of the voting rights of our shares. All of our shares are common stock without
  par value, each possessing equal voting rights. There is no other class of shares
  authorized.

Related Party Transactions

Please
  see the description of our Overriding Royalty Agreements in Item 10  Material
  Contracts and Agreements  Overriding Royalty Agreements.

Interests of Experts and Counsel

None.

Item 8.   Financial Information

Financial Statements and Other Financial Information

Financial
  statements are provided under Item 17.

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

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

Significant Changes

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

56

---





Item 9.    The Offer and Listing

Markets and Price History of the Stock

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

As
  of May 5, 2002, we had 21,051,196 shares of common stock outstanding. At that
  date, we estimate 66 shareholders of record resident in Canada holding 10,352,352
  shares of common stock and 821 shareholders of record resident in the United
  States holding 10,698,844 shares of common stock. Our shares of common stock
  are issued in registered form and the number of shares of common stock reported
  to be held by record holders in Canada and the United States is taken from the
  records of The CIBC Mellon Trust Company, the registrar and transfer agent for
  our shares of common stock. For U.S. reporting purposes, we are a foreign private
  issuer.

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

|                                  | VSE/TSX (in Cdn $) | NASDAQ SmallCap (in U.S.
      $)
|--------------------------------- | ------------------ | ---------------------------------
|                                  | High               | Low                              
|                                  |                    |                                  
|Nine-Month Fiscal Transition 2002 | 4.45               | 1.60                             
|Fiscal 2002                       | 2.63               | 1.55                             
|Fiscal 2001                       | 3.00               | 1.55                             
|Fiscal 2000                       | 2.05               | 1.44                             
|Fiscal 1999                       | 1.90               | 1.40                             
|                                  |                    |                                  

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

|Prices of Common Stock            | TSX (Cdn $) | NASDAQ Small Cap (U.S. $)
|--------------------------------- | ----------- | -------------------------
|                                  |             |                          
|Nine-Month Fiscal Transition 2002 | High        | Low                      
|                                  |             |                          
|Q1 ended June 30, 2002            | 2.00        | 1.60                     
|Q2 ended September 30, 2002       | 2.25        | 1.60                     
|Q3 ended December 31, 2002        | 4.45        | 1.90                     
|                                  |             |                          
|Fiscal 2002                       |             |                          
|                                  |             |                          
|Q1 ended June 30, 2001            | 2.52        | 1.69                     
|Q2 ended September 30, 2001       | 2.35        | 1.55                     
|Q3 ended December 31, 2001        | 2.05        | 1.56                     
|Q4 ended March 31, 2002           | 2.05        | 1.60                     

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                              
|         |                |                                  
|Apr/2003 | 4.70           | 3.91                             
|Mar/2003 | 4.44           | 3.55                             
|Feb/2003 | 3.89           | 3.40                             
|Jan/2003 | 4.10           | 3.10                             
|Dec/2002 | 4.45           | 2.35                             
|Nov/2002 | 2.60           | 2.25                             
|         |                |                                  

57

---





Item 10.  Additional Information

Memorandum and Articles of Association

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

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

Matters
  relating to our Directors

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

Directors
  power, in the absence of an independent quorum, to vote compensation to themselves
  or any members of their body -Part 12.2 of our Articles provides: The
  remuneration of the Directors as such may from time to time be determined by
  the Directors or, if the Directors shall so decide, by the members. Such remuneration
  may be in addition to any salary or other remuneration paid to any officer or
  employee of the Company as such who is also a Director.

Borrowing
  powers exercisable by the directors and how such borrowing powers can be varied
  -Part 8.1 of our Articles provides: The Directors may from time
  to time on behalf of the Company . . . borrow money in such manner and amount,
  on such security, from such sources and upon such terms and conditions as they
  think fit, issue bonds, debentures and other debt obligations either outright
  or as security for any liability or obligation of the Company or any other person,
  and mortgage . . . or give other security on the undertaking, or on the whole
  or any part of the property and assets, of the Company (both present and future).
  Part 8.2 states: Any bonds, debentures or other debt obligations of the
  Company may be issued at a discount, premium or otherwise, and with any special
  privileges as to redemption, surrender, drawing, allotment of or conversion
  into or exchange for shares or other securities, attending and voting at general
  meetings of the Company, appointment or election of Directors or otherwise and
  may by their terms be assignable free from any equities between the Company
  and the person to whom they were issued or any subsequent holder thereof, all
  as the Directors may determine.

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

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

Number
  of shares, if any required for directors qualification -Part
  12.3 of our Articles states that a Director shall not be required to hold
  a share in the capital of the Company as qualification for his office but shall
  be qualified as required by the Company Act to become or act as a Director.

Rights,
  preferences and restrictions attaching to each class of shares

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

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

58

---





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

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

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

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

Actions
  necessary to change the rights of holders of our stock

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

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

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

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

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

59

---





Limitations
  on rights to own securities of the Company

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

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

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

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

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

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

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

60

---





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

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

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

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

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

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

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

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

61

---





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

There
  are no such limitations in our Memorandum or Articles, but see discussion of
  our Permitted Bid Shareholder Protection Rights Plan in Item 14. Material
  Modifications to the Rights of Security Holders and Use of Proceeds  Shareholder
  Rights Plan.

**Provisions
  of our Memorandum or Articles governing the ownership threshold above which**shareholder
  ownership must be disclosed

There
  are no such provisions in our Memorandum or Articles.

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

The
  British Columbia Securities Act provides that a person that has direct or indirect
  beneficial ownership of, control or direction over, or a combination of direct
  or indirect beneficial ownership of, and of control or direction over, securities
  of the issuer carrying more than 10% of the voting rights attached to all the
  issuers outstanding voting securities must, within 10 days of becoming
  an insider, file an insider report in the required form effective
  the date on which the person became an insider, disclosing any direct or indirect
  beneficial ownership of, or control or direction over, securities of the reporting
  issuer. The British Columbia Securities Act also provides for the filing of
  a report by an insider of a reporting issuer who acquires or transfers
  securities of the issuer. This insider report must be filed within 10 days after
  the end of the month in which the change takes place.

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

Material Contracts and Agreements

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

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

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

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

62

---





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

Employment
  Agreements with Us

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

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

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

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

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

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

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

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

Exchange Controls

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

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

Except
  as provided in the Investment Canada Act ("the Act"), there are no limitations
  under the laws of Canada, the Province of British Columbia or in the charter
  or any other of our constituent documents on the right of foreigners to hold
  and/or vote the Common Stock.

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

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

63

---





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

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

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

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

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

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

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

Impact of the North American Free Trade Agreement

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

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

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

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

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

64

---





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

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

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

Taxation

The
  following paragraphs set forth certain United States and Canadian federal income
  tax considerations in connection with the purchase or sale of our shares of
  common stock.

The
  tax considerations are stated in general terms and are not intended to be advice
  to any particular shareholder. Each prospective investor is urged to consult
  his or her own tax advisor regarding the tax consequences of his or her purchase,
  ownership and disposition of shares of common stock.

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

Canadian
  Federal Income Tax Considerations

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

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

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

65

---





United
  States Federal Income Tax Considerations

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

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

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

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

Financing
  Exploration and Development Drilling Through Canadian Income Tax Incentives

In
  order to encourage investment in the exploration for and development of its
  mineral deposits, Canada has amended the Income Tax Act of Canada so as to allow
  Canadian taxpayers making investments in oil and gas companies to deduct on
  their personal income tax return qualifying amounts spent by the oil and gas
  company on Canadian property. Qualifying amounts cover 100% of annual "exploration"
  expenses and up to $1.0 million of annual "development" expenses. In addition
  to being able to deduct their investment as an expense, the investor receives
  stock in the company for his or her investment. The terms of this type of investment
  are usually set forth in a "Flow Through Agreement" in which the company agrees
  not to take as an income tax deduction the amount of the proceeds expended for
  exploration and/or development work, but to allow the deduction to flow
  through to the investors. This flow-through type of financing is of benefit
  only to Canadian taxpayers.

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

During
  Nine-Month Fiscal Transition 2002, Fiscal 2002 and Fiscal 2001 we did not raise
  any flow-through funding.

Item 11. Quantitative and Qualitative Disclosures About Market Risk

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

66

---





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

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

Market
  risk is the possibility that a change in the prices for natural gas, natural
  gas liquids, condensate and oil, foreign currency exchange rates, or interest
  rates will cause the value of a financial instrument to decrease or become more
  costly to settle. Our financial instruments in fiscal 2002 consist of cash and
  cash equivalents, accounts receivable, bank indebtedness, operating loan and
  accounts payable.

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

Commodities
  Price Risk

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

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

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

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

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

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

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

| | • | Commodity mix  our sales portfolio
        is comprised of natural gas, crude oil and natural gas liquids. Crude
        oil and natural gas liquids are sold at prices with volatilities that
        differ from those of natural gas; and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

67

---







| | • | Natural gas pricing mix  AECO pricing
        typically has a close correlation to NYMEX pricing, however, when the
        two become disconnected due to market dynamics, we are well-positioned
        to take advantage of premium pricing in either market area.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

Weighted Average Prices and the Effect of Adversity

We
  use a sensitivity analysis technique to evaluate the hypothetical effect that
  changes in the market value of natural gas, natural gas liquids and crude oil
  may have on the fair value of our gross revenues. The following table demonstrates
  the effects of declines in the weight-averaged prices of our revenue-generating
  commodities (see also Sensitivity Analysis under Item 5 in this
  Transition Report).

|                                  | Weight-Averaged Prices |                                          |        |       
|--------------------------------- | ---------------------- | ---------------------------------------- | ------ | ------
|Nine-Month Fiscal Transition 2002 | Achieved               | After Consideration of Adversity
      %
|                                  |                        |                                          |        |       
|                                  | Final                  | Entire                                   |        |       
|                                  | Quarter                | Period                                   | 10%    | 20%   
|                                  |                        |                                          |        |       
|Natural gas ( $/mcf)              | $5.50                  | $4.36                                    | $3.92  | $3.49 
|Natural gas liquids ($/bbl)       | $24.69                 | $20.90                                   | $18.81 | $16.72
|Crude oil ($/bbl)                 | $41.57                 | $41.40                                   | $37.26 | $33.12
|                                  |                        |                                          |        |       

Impact on Gross Revenues After Consideration of Pricing Adversity

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

|Nine-Month Fiscal Transition 2002 | Weight-Averaged Prices |                                          |        |       
|--------------------------------- | ---------------------- | ---------------------------------------- | ------ | ------
|($ 000s)                         | Achieved               | After Consideration of Adversity
      %
|                                  |                        |                                          |        |       
|                                  | Final                  | Entire                                   |        |       
|Commodity Type                    | Quarter                | Period                                   | 10%    | 20%   
|                                  |                        |                                          |        |       
|Natural gas                       | 7,017                  | 17,058                                   | 15,352 | 13,646
|Natural gas liquids               | 1,608                  | 4,012                                    | 3,611  | 3,210 
|Crude oil                         | 1,885                  | 3,052                                    | 2,747  | 2,442 
|                                  |                        |                                          |        |       

Credit
  Risk

In
  addition to market risk, our financial instruments involve, to varying degrees,
  risk associated with trade credit and risk associated with operatorship of joint
  venture properties. All of our accounts receivable are with customers or joint
  venture partners in the energy industry and are subject to normal industry credit
  risk. For example, approximately 58% of our December 31, 2002 balance of accounts
  receivable is due from fivecustomers, subject to normal credit risk.
  Further, while our largest producing properties during Fiscal Transition 2002
  were self-operated, five out of eleven active properties in which we have interests
  are operated by other industry companies.

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

Interest
  Rate Risk

We
  use a revolving, floating rate credit facility, therefore, we are exposed to
  fluctuations in short-term interest rates. Our current borrowing rate applied
  to the facility is Canadian Dollar Prime plus 3/8% per annum. To

68

---





minimize our exposure to rate variability, we occasionally
  invest a portion of our undrawn borrowing capacity in Bankers Acceptances
  (BAs). We are charged a standby fee of 1/8% per annum on our undrawn borrowing
  capacity.

We
  do not engage in interest rate swaps to hedge the interest rate exposure associated
  with the credit agreement. If market interest rates for short-term borrowings
  increase by 1%, the increase in our interest expense would be immaterial (see
  Sensitivity Analysis under Item 5 in this Transition Report).

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

Item 12.   Description of Securities Other than Equity Securities

Not
  applicable.

Part II.

Item 13.   Defaults, Dividend Arrearages and Delinquencies

None

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

Shareholder
  Rights Plan

Our
  Board of Directors adopted a Permitted Bid Shareholder Protection Rights Plan
  (Rights Plan) that was ratified by the shareholders at our Annual
  General Meeting on August 23, 2001.

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

Item 15.   Controls and Procedures

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

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

69

---





|Item 16.    | [Reserved]                            
|----------- | --------------------------------------
|            |                                       
|            | Not Applicable.                       
|            |                                       
|Item 16(A). | Audit Committee Financial Expert      
|            |                                       
|            | Not Applicable.                       
|            |                                       
|Item 16(B). | Code of Ethics                        
|            |                                       
|            | Not Applicable.                       
|            |                                       
|Item 16(C). | Principal Accountant Fees and Services
|            |                                       
|            | Not Applicable.                       

Part III.

Item 17.     Financial Statements

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

70

---



Financial Statements

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





---

AUDITORS REPORT

To the Shareholders of Dynamic Oil & Gas, Inc.

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

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

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

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

F-1

---

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

BALANCE SHEETS (in Canadian dollars)





|                                                  | **December 31** |   | March 31   |  
|------------------------------------------------- | --------------- | - | ---------- | -
|                                                  | **2002**        |   | 2002       |  
|                                                  | **$**           |   | $          |  
|                                                  |                 |   |            |  
|                                                  |                 |   |            |  
|ASSETS[note 4]                                    |                 |   |            |  
|Current                                           |                 |   |            |  
|Accounts receivable [note 10]                     | 6,426,761       |   | 5,979,532  |  
|Prepaid expenses                                  | 351,771         |   | 365,227    |  
|Income taxes receivable                           | 131,772         |   |           |  
|                                                  |                 |   |            |  
|Total current assets                              | 6,910,304       |   | 6,344,759  |  
|                                                  |                 |   |            |  
|Future income tax asset [note 7]                  |                |   | 279,000    |  
|Natural gas and oil interests [note 3]            | 36,568,076      |   | 30,365,636 |  
|Capital assets [note 3]                           | 168,366         |   | 162,499    |  
|                                                  |                 |   |            |  
|                                                  | 43,646,746      |   | 37,151,894 |  
|                                                  |                 |   |            |  
|                                                  |                 |   |            |  
|LIABILITIES AND SHAREHOLDERS EQUITY              |                 |   |            |  
|Current                                           |                 |   |            |  
|Bank indebtedness                                 | 1,519,923       |   | 842,812    |  
|Operating loan [note 4]                           | 11,075,000      |   | 14,750,000 |  
|Accounts payable and accrued liabilities          | 11,133,844      |   | 3,611,314  |  
|Income taxes payable                              |                |   | 421,360    |  
|                                                  |                 |   |            |  
|Total current liabilities                         | 23,728,767      |   | 19,625,486 |  
|                                                  |                 |   |            |  
|Deferred gain on sale [note 5]                    |                |   | 109,327    |  
|Provision for future removal and site restoration | 990,982         |   | 824,098    |  
|Future income tax liability [note 7]              | 682,300         |   |           |  
|                                                  |                 |   |            |  
|Total liabilities                                 | 25,402,049      |   | 20,558,911 |  
|                                                  |                 |   |            |  
|Share capital [note 6]                            | 20,720,629      |   | 20,914,522 |  
|Deficit                                           | (2,475,932      | ) | (4,321,539 | )
|                                                  |                 |   |            |  
|Total shareholders equity                        | 18,244,697      |   | 16,592,983 |  
|                                                  |                 |   |            |  
|                                                  | 43,646,746      |   | 37,151,894 |  
|                                                  |                 |   |            |  
|Commitments [notes 13 and 14]                     |                 |   |            |  

See accompanying notes and schedules

On behalf of the Board:

|Director:   /s/ Wayne J.
        Babcock | Director:   /s/ Donald K. Umbach
|---------------------------------------- | --------------------------------

F-2

---

Dynamic Oil & Gas, Inc.

STATEMENTS OF OPERATIONS AND DEFICIT
  (in Canadian dollars)





|                                              | **Nine Months** |   | Years Ended |  
|--------------------------------------------- | --------------- | - | ----------- | -
|                                              | **Ended**       |   | March 31    |  
|                                              | **December 31** |   |             |  
|                                              | **2002**        |   | 2002        |  
|                                              | **$**           |   | $           |  
|                                              |                 |   |             |  
|                                              |                 |   |             |  
|REVENUE                                       |                 |   |             |  
|Natural gas, liquids and oil sales            | 24,122,754      |   | 26,401,872  |  
|Royalties [note 11]                           | (5,521,583      | ) | (6,500,447  | )
|Production costs                              | (5,470,467      | ) | (5,845,958  | )
|                                              |                 |   |             |  
|                                              | 13,130,704      |   | 14,055,467  |  
|Alberta royalty tax credit                    | 178,098         |   | 159,274     |  
|                                              |                 |   |             |  
|                                              | 13,308,802      |   | 14,214,741  |  
|                                              |                 |   |             |  
|                                              |                 |   |             |  
|EXPENSES                                      |                 |   |             |  
|General and administrative [schedule 1]       | 1,926,162       |   | 2,347,212   |  
|Interest expense on operating loan            | 454,251         |   | 494,685     |  
|Interest income                               | (1,732          | ) | (22,066     | )
|                                              |                 |   |             |  
|                                              | 2,378,681       |   | 2,819,831   |  
|                                              |                 |   |             |  
|                                              |                 |   |             |  
|Earnings from operations before               |                 |   |             |  
|the following:                                | 10,930,121      |   | 11,394,910  |  
|Amortization and depletion [schedule 2]       | 6,426,785       |   | 12,172,943  |  
|Exploration expenses [schedule 3]             | 1,359,512       |   | 4,646,018   |  
|Gain on sale of natural gas and oil interests | (2,139          | ) | (4,566      | )
|                                              |                 |   |             |  
|Earnings (loss) before taxes                  | 3,145,963       |   | (5,419,485  | )
|                                              |                 |   |             |  
|Income tax expense (recovery) [note 7]        |                 |   |             |  
|- Current                                     | 207,000         |   | 57,600      |  
|- Future                                      | 961,300         |   | (1,958,000  | )
|                                              |                 |   |             |  
|Net earnings (loss)                           | 1,977,663       |   | (3,519,085  | )
|                                              |                 |   |             |  
|Deficit, beginning of year                    | (4,321,539      | ) | (695,279    | )
|Premium on purchase and cancellation of       |                 |   |             |  
|common shares [note 6[d]]                     | (132,056        | ) | (107,175    | )
|                                              |                 |   |             |  
|Deficit, end of year                          | (2,475,932      | ) | (4,321,539  | )
|                                              |                 |   |             |  
|                                              |                 |   |             |  
|Earnings per share [note 8]                   |                 |   |             |  
|basic                                         | 0.10            |   | (0.17       | )
|diluted                                       | 0.10            |   | (0.17       | )
|                                              |                 |   |             |  

See accompanying notes and schedules

F-3

---

Dynamic Oil & Gas, Inc.

STATEMENTS OF CASH FLOWS (in Canadian dollars)





|                                                  | **Nine Months** |   | Years Ended |  
|------------------------------------------------- | --------------- | - | ----------- | -
|                                                  | **Ended**       |   | March 31    |  
|                                                  | **December 31** |   |             |  
|                                                  | **2002**        |   | 2002        |  
|                                                  | $               |   | $           |  
|                                                  |                 |   |             |  
|                                                  |                 |   |             |  
|OPERATING ACTIVITIES                              |                 |   |             |  
|Net earnings (loss)                               | 1,977,663       |   | (3,519,085  | )
|Add (deduct) items not involving cash:            |                 |   |             |  
|Amortization and depletion                        | 6,426,785       |   | 12,172,943  |  
|Future income tax expense                         | 961,300         |   | (1,958,000  | )
|Exploration expenses                              | 1,359,512       |   | 4,646,018   |  
|Gain on sale of natural gas and oil interests     | (2,139          | ) | (4,566      | )
|                                                  |                 |   |             |  
|Funds flow from operations                        | 10,723,121      |   | 11,337,310  |  
|Changes in non-cash working capital affecting     |                 |   |             |  
|operating activities [note
      9[a]]            | 646,829         |   | (1,558,807  | )
|                                                  |                 |   |             |  
|Cash provided by operating activities             | 11,369,950      |   | 9,778,503   |  
|                                                  |                 |   |             |  
|                                                  |                 |   |             |  
|FINANCING ACTIVITIES                              |                 |   |             |  
|Bank indebtedness                                 | 677,111         |   | 842,812     |  
|Operating loan                                    | (3,675,000      | ) | 14,750,000  |  
|Shares issued for cash                            |                |   | 455,420     |  
|Share repurchases                                 | (325,948        | ) | (289,793    | )
|                                                  |                 |   |             |  
|Cash (used in) provided by financing activities   | (3,323,837      | ) | 15,758,439  |  
|                                                  |                 |   |             |  
|                                                  |                 |   |             |  
|INVESTING ACTIVITIES                              |                 |   |             |  
|Purchase of capital assets                        | (84,420         | ) | (116,180    | )
|Natural gas and oil interests                     | (12,493,116     | ) | (21,994,897 | )
|Exploration expenses                              | (1,359,512      | ) | (4,646,018  | )
|Proceeds on sale of natural gas and oil interests | 2,139           |   | 4,566       |  
|Changes in non-cash working capital affecting     |                 |   |             |  
|investing activities [note
      9[b]]            | 5,888,796       |   | (2,277,861  | )
|                                                  |                 |   |             |  
|Cash used in investing activities                 | (8,046,113      | ) | (29,030,390 | )
|                                                  |                 |   |             |  
|                                                  |                 |   |             |  
|(Decrease) increase in cash and cash equivalents  |                |   | (3,493,448  | )
|Cash and cash equivalents, beginning of year      |                |   | 3,493,448   |  
|                                                  |                 |   |             |  
|Cash and cash equivalents, end of year            |                |   |            |  
|                                                  |                 |   |             |  
|                                                  |                 |   |             |  
|Supplemental disclosures of cash flow information |                 |   |             |  
|Cash paid during the year for:                    |                 |   |             |  
|Interest                                          | 459,237         |   | 589,549     |  
|Income taxes                                      | 760,132         |   | 1,167,720   |  
|                                                  |                 |   |             |  

See accompanying notes and schedules

F-4

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



1. DESCRIPTION OF BUSINESS

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting principles

The Company prepares its accounts in accordance with Canadian generally accepted
  accounting principles which, as applied in these financial statements, conform
  in all material respects with United States generally accepted accounting principles,
  except as explained in Note 12.

Change in fiscal year end

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

Results of Operations

|                                   | TwelveMonths
      Ended |   | NineMonths
      Ended |  
|---------------------------------- | ------------------------ | - | ---------------------- | -
|                                   |                          |   |                        |  
|                                   | December 31              |   | December 31            |  
|                                   | 2002                     |   | 2001                   |  
|                                   |                          |   |                        |  
|                                   | (unaudited)              |   | (unaudited)            |  
|                                   |                          |   |                        |  
|Revenue                            | 30,730,477               |   | 31,658,397             |  
|Net earnings (loss)                | 287,145                  |   | 2,248,205              |  
|Net earnings (loss) per share      |                          |   |                        |  
|basic                              | 0.01                     |   | 0.11                   |  
|diluted                            | 0.01                     |   | 0.11                   |  
|Cash flows                         |                          |   |                        |  
|- provided by operating activities | 15,128,790               |   | 14,949,163             |  
|- (used in) provided by financing  |                          |   |                        |  
|activities                         | (4,331,528               | ) | 12,972,031             |  
|- used in investing activities     | (10,814,155              | ) | (29,877,314            | )
|                                   |                          |   |                        |  

F-5

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



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

Stock-based compensation

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

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

Natural gas and oil interests

The Company uses the successful efforts method to account
  for its natural gas and oil interests. Lease acquisition costs are amortized
  over their holding period prior to the discovery of proved producing reserves.
  Geological and geophysical costs are expensed in the period in which they are
  incurred and costs of drilling an unsuccessful well are expensed when it becomes
  known the well did not result in a discovery of proved reserves. All other costs
  of exploring and developing for proved reserves become capitalized natural gas
  and oil interests.

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

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

F-6

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



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

Joint interests

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

Earnings per share

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

Future removal and site restoration

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

Capital assets

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

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

Use of estimates

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

F-7

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



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

Income taxes

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

Foreign currency translation

The Company follows the temporal method of accounting for
  the translation of foreign currency amounts into Canadian dollars. Under this
  method, all monetary assets and liabilities expressed in foreign currencies
  are translated at rates of exchange in effect at the end of the year. All other
  assets and liabilities are translated at the rates prevailing at the dates the
  assets were acquired or liabilities incurred. The resulting foreign currency
  translation gains and losses are included in the determination of net income.
  Revenues and expenses are translated at the average exchange rate for the period.

Measurement uncertainty

The amounts recorded for depletion and amortization of natural
  gas and oil interests and the provision for future removal and site restoration
  are based on estimates. Assessments for impairments in asset carrying costs
  are based on estimates of proved producing reserves, production rates, natural
  gas and oil prices, future costs and other relevant assumptions. By their nature
  these estimates are subject to measurement uncertainty and the effect on the
  financial statements of changes in such estimates in future years could be significant.

Revenue recognition

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

Deferred gain on sale and lease back

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

F-8

---



Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



3. NATURAL GAS AND OIL INTERESTS, AND CAPITAL ASSETS

|                                           |            |  | Accumulated      |  |            | 
|------------------------------------------ | ---------- |  | ---------------- |  | ---------- | 
|                                           |            |  | Amortization and |  | Net Book   | 
|                                           | **Cost**   |  | Depletion        |  | Value      | 
|                                           | **$**      |  | **$**            |  | **$**      | 
|                                           |            |  |                  |  |            | 
|                                           |            |  |                  |  |            | 
|December 31, 2002                          |            |  |                  |  |            | 
|Natural gas and oil interests              | 61,657,575 |  | 25,089,499       |  | 36,568,076 | 
|Furniture, fixtures and computer equipment | 538,153    |  | 369,787          |  | 168,366    | 
|                                           |            |  |                  |  |            | 
|                                           |            |  |                  |  |            | 
|March 31, 2002                             |            |  |                  |  |            | 
|Natural gas and oil interests              | 49,453,746 |  | 19,088,110       |  | 30,365,636 | 
|Furniture, fixtures and computer equipment | 453,733    |  | 291,234          |  | 162,499    | 
|                                           |            |  |                  |  |            | 

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

In the nine-month period ended December 31, 2002, the Company
  recorded asset write-downs of $445,467 [year ended March 31, 2002 - $6,783,248;
  year ended March 31, 2001 - $35,712] to reflect the excess of the net book value
  of the Companys natural gas and oil interests over its estimated recoverable
  amounts. The write-downs were included in amortization and depletion expense.

4. OPERATING LOAN

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

F-9

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



5. ST. ALBERT SALE AND LEASEBACK

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

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

6. SHARE CAPITAL

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

|[a] | Issued and Outstanding                                                  
|--- | ------------------------------------------------------------------------
|    |                                                                         
|    | The following table sets forth the issued and outstanding common shares:
|    |                                                                         

| |                                                       | Number of  |   |            |  
| | ----------------------------------------------------- | ---------- | - | ---------- | -
| |                                                       | Shares     |   | $          |  
| |                                                       |            |   |            |  
| |                                                       |            |   |            |  
| | Balance, March 31, 2001                               | 20,145,930 |   | 20,641,720 |  
| | Stock options exercised                               | 495,100    |   | 455,420    |  
| | Share repurchases and cancellations [note
      6[d]] | (178,800   | ) | (182,618   | )
| |                                                       |            |   |            |  
| | Balance, March 31, 2002                               | 20,462,230 |   | 20,914,522 |  
| | Share repurchases and cancellations [note
      6[d]] | (189,700   | ) | (193,893   | )
| |                                                       |            |   |            |  
| | Balance, December 31, 2002                            | 20,272,530 |   | 20,720,629 |  
| |                                                       |            |   |            |  

F-10

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002

**6.  SHARE CAPITAL (contd.)**

|**[b]** | **Stock Option Plan and Options Outstanding**                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|        |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|        | Under the Companys stock option
        plan, the Company has the ability to grant options to inside directors,
        officers, employees and consultants with a maximum term of five years.
        Those granted prior to February 28, 2001 vest upon date of grant; those
        granted on February 28, 2001 and thereafter, vest in equal amounts over
        three years from the date of grant. During the nine months ended December
        31, 2002, all options issued were to either inside directors, officers
        or employees.
      In addition, under the plan, options granted to the
        Companys outside directors have a maximum term of ten years and
        vest upon date of grant.
      The exercise price of each option granted under the
        plan equals the amount designated in the individual agreement, which is
        based on the fair value of the stock at the date of grant.
      A summary of the status of the Companys stock
        option plan as of December 31, 2002, March 31, 2002, and March 31, 2001
        is presented below:
|        |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         

| |                                                                                                                                                                                                         | December 31 |  | March 31     |  | March 31  |  
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ----------- |  | ------------ |  | --------- | -
| |                                                                                                                                                                                                         | 2002        |  | 2002         |  | 2001      |  
| |                                                                                                                                                                                                         |             |  |              |  |           |  
| |                                                                                                                                                                                                         | Number      |  | Weighted     |  | Number    |  
| |                                                                                                                                                                                                         | of          |  | average      |  | of        |  
| |                                                                                                                                                                                                         | shares      |  | option price |  | shares    |  
| |                                                                                                                                                                                                         | #           |  | $            |  | #         |  
| |                                                                                                                                                                                                         |             |  |              |  |           |  
| |                                                                                                                                                                                                         |             |  |              |  |           |  
| | Outstanding at beginning of period                                                                                                                                                                      | 1,930,250   |  | 1.83         |  | 1,855,350 |  
| | Granted                                                                                                                                                                                                 | 147,500     |  | 1.88         |  | 570,000   |  
| | Exercised                                                                                                                                                                                               |            |  |             |  | (495,100  | )
| |                                                                                                                                                                                                         |             |  |              |  |           |  
| | Outstanding at period end                                                                                                                                                                               | 2,077,750   |  | 1.83         |  | 1,930,250 |  
| |                                                                                                                                                                                                         |             |  |              |  |           |  
| | Options exercisable at period end                                                                                                                                                                       | 1,641,250   |  | 1.84         |  | 1,458,750 |  
| |                                                                                                                                                                                                         |             |  |              |  |           |  
| |                                                                                                                                                                                                         |             |  |              |  |           |  
| | Exercise prices for the options outstanding
        as of December 31, 2002 ranged from 1.45 to 2.95 per share. These options
        have a weighted average remaining contractual life of 2.90 years.



F-11

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002

6.  SHARE CAPITAL (contd.)

|[c] | Pro Forma Net Income - Fair-Value Based Method of Accounting
      for Stock Options                                                                                                       
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                            
|    | The following shows pro forma net income
        and earnings per common share had the Company applied the fair value based
        method of accounting for all stock options outstanding.

| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      | December 31 | 
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ----------- | 
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      | 2002        | 
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      | $           | 
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |             | 
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |             | 
| | Net Earnings:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |             | 
| | - as reported                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        | 1,977,663   | 
| | - pro forma                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          | 1,771,987   | 
| | Basic earnings per common share:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     |             | 
| | - as reported                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        | 0.10        | 
| | - pro forma                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          | 0.09        | 
| | Diluted earnings per common share:                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |             | 
| | - as reported                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        | 0.10        | 
| | - pro forma                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          | 0.09        | 
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |             | 
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |             | 
| | The Black-Scholes options
        valuation model was used to estimate the fair value of non-employee options,
        which have no vesting restrictions and are fully transferable. In addition,
        option valuation models require the input of highly subjective assumptions
        including the expected stock price volatility. As the Companys employee
        and director stock options have characteristics different from those of
        non-employee options, and changes in the subjective input assumptions
        can materially affect the fair value estimate, the existing models do
        not necessarily provide a reliable single measure of the fair value of
        its employee and director stock options. The fair value of option grants
        using the Black-Scholes model is estimated on the date of grant using
        the following weighted-average assumptions:
| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     

| |                                                                                                                                                   | December 31 | 
| | ------------------------------------------------------------------------------------------------------------------------------------------------- | ----------- | 
| |                                                                                                                                                   | 2002        | 
| |                                                                                                                                                   | $           | 
| |                                                                                                                                                   |             | 
| |                                                                                                                                                   |             | 
| | Dividend yield                                                                                                                                    | 0%          | 
| | Expected volatility                                                                                                                               | 47%         | 
| | Risk-free interest rate                                                                                                                           | 5%          | 
| | Expected lives                                                                                                                                    | 3 years     | 
| |                                                                                                                                                   |             | 
| |                                                                                                                                                   |             | 
| | The weighted average fair value per share
        of stock options granted during the nine month period ended December 31,
        2002 is $0.91.



F-12

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002

6.  SHARE CAPITAL (contd.)

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

| | Normal course issuer bid date of                                                                 |             | Share repurchases/      
| | ------------------------------------------------------------------------------------------------ | ----------- | ------------------------
| | Commencement                                                                                     | Termination | cancellations authorized
| |                                                                                                  |             |                         
| |                                                                                                  |             |                         
| | 1-May-02                                                                                         | 31-Mar-03   | 1,000,000               
| | 9-Apr-01                                                                                         | 31-Mar-02   | 1,000,000               
| | 1-Oct-99                                                                                         | 30-Sep-00   | 1,000,000               
| |                                                                                                  |             |                         
| |                                                                                                 
| | Under these normal course issuer bids,
        the Company purchased and recorded the following:
| |                                                                                                 

| |                                          | December 31 |   | March 31 |   | March 31 |  
| | ---------------------------------------- | ----------- | - | -------- | - | -------- | -
| |                                          | 2002        |   | 2002     |   | 2001     |  
| |                                          |             |   |          |   |          |  
| |                                          | #           |   | $        |   | #        |  
| |                                          |             |   |          |   |          |  
| |                                          |             |   |          |   |          |  
| | Bid termination date: 31-Mar-03          | (189,700    | ) | (325,948 | ) |          |  
| | Bid termination date: 31-Mar-02          |            |   |         |   | (178,800 | )
| | Bid termination date: 30-Sep-00          |            |   |         |   |         |  
| |                                          |             |   |          |   |          |  
| |                                          | (189,700    | ) | (325,948 | ) | (178,800 | )
| |                                          |             |   |          |   |          |  
| | Average purchase price                   | $1.72       |   |          |   | $1.62    |  
| | Recorded as an increase of deficit       |             |   | 132,056  |   |          |  
| |                                          |             |   |          |   |          |  
| | Recorded as a reduction of share capital |             |   | (193,892 | ) |          |  
| |                                          |             |   |          |   |          |  

F-13

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



7. INCOME TAXES

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

|                                                        | **December 31** |   | March 31 |  
|------------------------------------------------------- | --------------- | - | -------- | -
|                                                        | **2002**        |   | 2002     |  
|                                                        | **$**           |   | $        |  
|                                                        |                 |   |          |  
|                                                        |                 |   |          |  
|Long term future tax assets (liabilities):              |                 |   |          |  
|CCA in excess of book depreciation                      | (1,015,300      | ) | (46,000  | )
|Finance charges                                         | 1,000           |   | 2,000    |  
|Deferred gain recognized for tax purposes               |                |   | 46,000   |  
|Provision for future removal and site restoration costs | 332,000         |   | 277,000  |  
|                                                        |                 |   |          |  
|Net future tax (liabilities) assets                     | (682,300        | ) | 279,000  |  
|                                                        |                 |   |          |  

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

|                                   | December 31 |   | March 31 | March 31 |           
|---------------------------------- | ----------- | - | -------- | -------- | ----------
|                                   | **2002**    |   | 2002     | 2001     |           
|                                   | $           |   | %        |          | $         
|                                   |             |   |          |          |           
|                                   |             |   |          |          |           
|Tax at combined federal            |             |   |          |          |           
|and provincial rates               | 1,333,000   |   | 42.37    |          | (2,371,000
|Tax effect of non-deductible       |             |   |          |          |           
|crown royalties                    | 898,400     |   |          |          | 1,068,000 
|Tax effect of income not           |             |   |          |          |           
|taxable                            | (70,500     | ) |          |          | (64,900   
|Tax effect of resource allowance   | (1,017,600  | ) |          |          | (1,290,300
|Large Corporation Tax in excess of |             |   |          |          |           
|surtax                             | 25,000      |   |          |          | 49,000    
|Effect of changes in tax rates     |            |   |          |          | 708,800   
|                                   |             |   |          |          |           
|                                   | 1,168,300   |   |          |          | (1,900,400
|                                   |             |   |          |          |           

F-14

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



8. EARNINGS PER SHARE

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

|                                   | **December 31** |  | March 31   |   | March 31   | 
|---------------------------------- | --------------- |  | ---------- | - | ---------- | 
|                                   | **2002**        |  | 2002       |   | 2001       | 
|                                   | $               |  | $          |   | $          | 
|                                   |                 |  |            |   |            | 
|                                   |                 |  |            |   |            | 
|Numerator                          |                 |  |            |   |            | 
|Net earnings (loss) for the period | 1,977,663       |  | (3,519,085 | ) | 9,714,030  | 
|                                   |                 |  |            |   |            | 
|                                   |                 |  |            |   |            | 
|Denominator                        |                 |  |            |   |            | 
|Weighted average number of common  |                 |  |            |   |            | 
|shares outstanding                 | 20,357,153      |  | 20,365,031 |   | 19,937,585 | 
|Effect of dilutive stock options   | 197,078         |  | 101,512    |   | 507,934    | 
|                                   |                 |  |            |   |            | 
|                                   | 20,554,231      |  | 20,466,543 |   | 20,444,979 | 
|                                   |                 |  |            |   |            | 
|                                   |                 |  |            |   |            | 
|Basic earnings (loss) per share    | 0.10            |  | (0.17      | ) | 0.49       | 
|Diluted earnings (loss) per share  | 0.10            |  | (0.17      | ) | 0.48       | 
|                                   |                 |  |            |   |            | 

9. CHANGES IN NON-CASH WORKING CAPITAL BALANCES

|[a] | Changes affecting operating activities comprise:
|--- | ------------------------------------------------
|    |                                                 

| |                                          | **December 31** |   | March 31   |   | March 31   |  
| | ---------------------------------------- | --------------- | - | ---------- | - | ---------- | -
| |                                          | **2002**        |   | 2002       |   | 2001       |  
| |                                          | $               |   | $          |   | $          |  
| |                                          |                 |   |            |   |            |  
| |                                          |                 |   |            |   |            |  
| | Accounts receivable                      | (968,683        | ) | (581,264   | ) | (2,463,146 | )
| | Prepaid expenses                         | 13,456          |   | (124,761   | ) | (122,782   | )
| | Accounts payable and accrued liabilities | 2,155,188       |   | (728,998   | ) | 3,136,946  |  
| | Income taxes payable                     | (553,132        | ) | (123,784   | ) | 545,144    |  
| |                                          |                 |   |            |   |            |  
| |                                          | 646,829         |   | (1,558,807 | ) | 1,096,162  |  
| |                                          |                 |   |            |   |            |  

F-15

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



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

|[b] | Changes affecting investing activities comprise:
|--- | ------------------------------------------------

| |                     | **December31** |  | March 31   |   | March 31  | 
| | ------------------- | -------------- |  | ---------- | - | --------- | 
| |                     | **2002**       |  | 2002       |   | 2001      | 
| |                     | $              |  | $          |   | $         | 
| |                     |                |  |            |   |           | 
| |                     |                |  |            |   |           | 
| | Accounts receivable | 521,453        |  | (953,434   | ) | 217,404   | 
| | Accounts payable    | 5,367,343      |  | (1,324,427 | ) | 892,484   | 
| |                     |                |  |            |   |           | 
| |                     | 5,888,796      |  | (2,277,861 | ) | 1,109,888 | 
| |                     |                |  |            |   |           | 

10. FINANCIAL INSTRUMENTS

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

Substantially all of the Companys accounts receivable
  at December 31, 2002, and March 31, 2002 result from the sale of natural gas,
  natural gas liquids and oil to other companies in the oil and gas industry.
  This concentration of customers may impact the Companys overall credit
  risk, either positively or negatively, in that such entities may be similarly
  affected by industry-wide changes in economic or other conditions. Historically
  to date, the Company has not incurred credit losses against its receivables.
  At December 31, 2002 five customers represent 56% of the accounts receivable
  balance.

11. OVERRIDING ROYALTY

Three of the Companys officers receive compensation
  pursuant to royalty agreements that have previously been approved by shareholders.
  The Company pays an overriding royalty interest of 1% of the Companys
  share of gross monthly production of all petroleum substances produced or deemed
  to be produced and marketed from or allocated to each well on all lands acquired
  by the Company since June 1, 1986 for two of the three officers and June 1,
  1987 for the third officer. In the nine-month period ending December 31, 2002,
  the overriding royalty expense included in royalties is $681,493 [years ended
  March 31, 2002 - $745,994; March 31, 2001 - $934,338].

F-16

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



12.  RECONCILIATION OF GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

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

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

|                                           | **For the Nine Months** |   | For the Year   |   | For the Year   |  
|------------------------------------------ | ----------------------- | - | -------------- | - | -------------- | -
|                                           | **Ended December 31**   |   | Ended March 31 |   | Ended March 31 |  
|                                           | **2002**                |   | 2002           |   | 2001           |  
|                                           | $                       |   | $              |   | $              |  
|                                           |                         |   |                |   |                |  
|                                           |                         |   |                |   |                |  
|Net earnings (loss) under Canadian GAAP    | 1,977,663               |   | (3,519,085     | ) | 9,714,030      |  
|Options issued for services [a]            | (4,933                  | ) |               |   | (20,100        | )
|Ceiling test adjustment to natural gas     |                         |   |                |   |                |  
|properties [b]                             | (332,000                | ) | (216,100       | ) |               |  
|Income taxes [c]                           | 141,400                 |   | 669,100        |   | (577,000       | )
|                                           |                         |   |                |   |                |  
|Net earnings (loss) and comprehensive      |                         |   |                |   |                |  
|earnings (loss) under U.S.
      GAAP      | 1,782,130               |   | (3,066,085     | ) | 9,116,930      |  
|                                           |                         |   |                |   |                |  
|Common shares - weighted average           | 20,357,153              |   | 20,365,031     |   | 19,937,585     |  
|Net earnings (loss) per common share under |                         |   |                |   |                |  
|U.S. GAAP                                  |                         |   |                |   |                |  
|- basic                                    | 0.09                    |   | (0.15          | ) | 0.46           |  
|- diluted                                  | 0.09                    |   | (0.15          | ) | 0.45           |  
|                                           |                         |   |                |   |                |  

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

|                                  | **December 31** |   | March 31   |  
|--------------------------------- | --------------- | - | ---------- | -
|                                  | **2002**        |   | 2002       |  
|                                  |                 |   |            |  
|                                  | **Canadian**    |   | **U.S.**   |  
|                                  | **Basis**       |   | **Basis**  |  
|                                  | $               |   | $          |  
|                                  |                 |   |            |  
|                                  |                 |   |            |  
|Future income tax asset [c]       |                |   |           |  
|Future income tax liability [c]   | 682,300         |   | 540,900    |  
|Natural gas and oil interests [b] | 36,568,076      |   | 36,236,076 |  
|Share capital [a, d]              | 20,720,629      |   | 21,693,722 |  
|Deficit [a, b, c, d]              | (2,015,480      | ) | (1,640,052 | )
|                                  |                 |   |            |  

F-17

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002

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

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

| |                                    | March 31   |   | March 31  | 
| | ---------------------------------- | ---------- | - | --------- | 
| |                                    | 2002       |   | 2001      | 
| |                                    | $          |   | $         | 
| |                                    |            |   |           | 
| |                                    |            |   |           | 
| | Net Earnings:                      |            |   |           | 
| | - as reported                      | (3,519,085 | ) | 9,714,030 | 
| | - pro forma                        | (3,356,108 | ) | 9,313,819 | 
| | Basic earnings per common share:   |            |   |           | 
| | - as reported                      | (0.17      | ) | 0.49      | 
| | - pro forma                        | (0.16      | ) | 0.47      | 
| | Diluted earnings per common share: |            |   |           | 
| | - as reported                      | (0.17      | ) | 0.48      | 
| | - pro forma                        | (0.16      | ) | 0.46      | 
| |                                    |            |   |           | 

F-18

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



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

|    | For the nine months ended December 31,
        2002, the net earnings (loss) that would be disclosed to SFAS No. 123
        is consistent with the amounts shown in note 6[c]. The weighted average
        assumptions used in the Black-Scholes valuation (refer to note 6[c] for
        discussion of the model) for the years ended March 31, 2002 and 2001 were
        as follows:                                                                                                                                                                                                                                                                                             
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|    | Dividend yield                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|    | Expected volatility                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|    | Risk-free interest rate                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|    | Expected lives                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|[b] | Under the successful efforts method of
        accounting, according to Canadian GAAP, the net carrying cost of oil and
        gas properties in producing cost centres is limited to an estimated recoverable
        amount, which is the aggregate of future net operating revenues from proved
        producing reserves net of certain costs (the Canadian ceiling test).
        Under U.S. GAAP, costs accumulated in each cost centre are limited to
        an amount equal to the present value, using an annual cash flow discount
        rate of 10%, of the estimated future net operating revenues from proved
        producing reserves (the U.S. ceiling test).
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|[c] | Effective April 1, 1999, the Company
        adopted the new Canadian GAAP recommendations with respect to income taxes
        which requires application of the liability method of tax allocation,
        similar to the requirements under US GAAP. However, there remains a difference
        between Canadian and US GAAP, as Canadian GAAP requires that deferred
        income tax balances be adjusted to reflect substantively enacted rates
        rather than the current legislated tax rates under US GAAP.                                                                                                                                                          
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|[d] | Share issue costs are charged directly
        to retained earnings under Canadian GAAP and are charged directly to share
        capital under US GAAP. The total share issue costs charged to share capital
        was $570,961.                                                                                                                                                                                                                                                                                                                                                                                                                                                    



F-19

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002

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

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

**13.  COMMITMENTS**

|[a] | Operating lease                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|    | The Company has entered into an operating
        lease in respect of its office premises. Minimum payments under this lease
        commitment, including estimated operating costs over the next two years
        are $72,329 and $6,027 for the fiscal years ending December 31, 2003 and
        2004, respectively.                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|[b] | Future removal and site restoration costs                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
|    | The Company is responsible for the future
        removal and site restoration related to its natural gas and oil properties
        at the end of their useful lives. The Company currently estimates the
        total amount of this future liability to be approximately $2,110,750,
        of which $166,883 has been accrued in the current year with $1,085,113
        remaining to be accrued in the future. Actual costs may differ from those
        estimated due to changes in legislation and estimated costs.



F-20

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS
  (in Canadian dollars)

December 31, 2002



14. ECONOMIC DEPENDENCY

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

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

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

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

F-21

---

Dynamic Oil & Gas, Inc.

Schedule 1 GENERAL AND ADMINISTRATIVE (in Canadian dollars)

|                          | **Nine Months** |   | Year Ended |  
|------------------------- | --------------- | - | ---------- | -
|                          | **Ended**       |   | March 31   |  
|                          | **December 31** |   |            |  
|                          | **2002**        |   | 2002       |  
|                          | $               |   | $          |  
|                          |                 |   |            |  
|                          |                 |   |            |  
|Advertising and promotion | 180,249         |   | 250,792    |  
|Insurance                 | 121,427         |   | 122,583    |  
|Interest                  | 32,967          |   | 98,087     |  
|Office and printing       | 387,029         |   | 432,947    |  
|Professional fees         | 474,120         |   | 530,203    |  
|Provincial capital taxes  | 17,836          |   | 83,062     |  
|Regulatory and other fees | 81,523          |   | 72,472     |  
|Rent                      | 66,410          |   | 89,581     |  
|Salaries and benefits (1) | 783,706         |   | 1,086,958  |  
|Telephone                 | 16,076          |   | 16,423     |  
|Travel                    | 39,689          |   | 23,054     |  
|Cost recoveries           | (274,870        | ) | (458,950   | )
|                          |                 |   |            |  
|                          | 1,926,162       |   | 2,347,212  |  
|                          |                 |   |            |  

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

Schedule 2AMORTIZATION AND DEPLETION(in Canadian dollars)

|                                              |                 |   |            |   |           |  
|--------------------------------------------- | --------------- | - | ---------- | - | --------- | -
|                                              | **Nine Months** |   | Year Ended |  
|                                              | **Ended**       |   | March 31   |  
|                                              | **December 31** |   |            |  
|                                              | **2002**        |   | 2002       |   | 2001      |  
|                                              | $               |   | $          |   | $         |  
|                                              |                 |   |            |   |           |  
|                                              |                 |   |            |   |           |  
|Amortization and depletion                    | 6,369,230       |   | 12,118,849 |   | 3,132,663 |  
|Future removal and site restoration provision | 166,883         |   | 284,368    |   | 184,925   |  
|Amortization of deferred financing costs      |                |   |           |   | 1,412     |  
|Amortization of deferred gain on sale         | (109,328        | ) | (230,274   | ) | (312,036  | )
|                                              |                 |   |            |   |           |  
|                                              | 6,426,785       |   | 12,172,943 |   | 3,006,964 |  
|                                              |                 |   |            |   |           |  

F-22

---

Dynamic Oil & Gas, Inc.

Schedule 3 EXPLORATION EXPENSES (in Canadian dollars)

|                            |                 |  |            |  |           | 
|--------------------------- | --------------- |  | ---------- |  | --------- | 
|                            | **Nine Months** |  | Year Ended | 
|                            | **Ended**       |  | March 31   | 
|                            | **December 31** |  |            | 
|                            | 2002            |  | 2002       |  | 2001      | 
|                            | $               |  | $          |  | $         | 
|                            |                 |  |            |  |           | 
|                            |                 |  |            |  |           | 
|Drilling                    | 325,477         |  | 3,821,374  |  | 667,684   | 
|Seismic data activity       | 846,984         |  | 649,216    |  | 1,101,969 | 
|Non-producing lease rentals | 138,051         |  | 64,605     |  | 51,856    | 
|Property investigations     | 49,000          |  | 110,823    |  | 101,685   | 
|                            |                 |  |            |  |           | 
|                            | 1,359,512       |  | 4,646,018  |  | 1,923,194 | 
|                            |                 |  |            |  |           | 

F-23

---

|Item 18.     Financial
      Statements
|---------------------------------------
|                                       
|(a)                                    
|                                       
|(b)                                    
|                                       
|Item 19. Exhibits                      
|                                       
|(a)                                    
|                                       
|(b)                                    

70

---





Signatures

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

Date: May 14, 2003

Dynamic Oil & Gas, Inc.

|By: /s/ Michael A. Bardell                   
|---------------------------------------------
|                                             
|Michael A. Bardell                           
|Chief Financial Officer & Corporate Secretary



|Certification                     
|----------------------------------
|                                  
|I, Wayne J. Babcock, certify that:
|                                  
|1.                                
|                                  
|2.                                
|                                  
|3.                                
|                                  
|4.                                
|                                  
|                                  
|                                  
|                                  
|                                  
|5.                                
|                                  
|                                  
|                                  
|                                  
|                                  
|6.                                

Date: May 16, 2003

/s/ Wayne J. Babcock
  Wayne J. Babcock,
  President and Chief Executive Officer

71

---





|Certification                       
|------------------------------------
|                                    
|I, Michael A. Bardell, certify that:
|                                    
|1.                                  
|                                    
|2.                                  
|                                    
|3.                                  
|                                    
|4.                                  
|                                    
|                                    
|                                    
|                                    
|                                    
|5.                                  
|                                    
|                                    
|                                    
|                                    
|                                    
|6.                                  

Date: May 16, 2003

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

72

---





INDEX TO EXHIBITS

|                   |  |                                                                                                                                                                                                                                                                                                                    | Sequentially 
|------------------ |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | -------------
|Exhibit Numbers    |  | EXHIBITS                                                                                                                                                                                                                                                                                                           | Numbered Page
|                   |  |                                                                                                                                                                                                                                                                                                                    |              
|1(a) and 2(a)(i)   |  | Certificate of Incorporation and Articles/By-laws.
      (1)                                                                                                                                                                                                                                                       |              
|1(b) and 2(a)(ii)  |  | Certificate of Increase of Authorized Capital
      of the Company and NameChange.(3)                                                                                                                                                                                                                              |              
|1(c) and 2(a)(iii) |  | Amendment to Articles of Incorporation re Staggered
      Board (6)                                                                                                                                                                                                                                                | 76           
|1(d) and 2(a)(iv)  |  | Corporate Governance Committee Guidelines                                                                                                                                                                                                                                                                          |              
|2(a)(v)            |  | Shareholder Rights Plan Agreement.(3)                                                                                                                                                                                                                                                                              |              
|4(i)               |  | Joint Bidding Agreement by and between Imperial
      Oil Limited St. AlbertProperty Package, dated February
      5, 1997. (1)                                                                                                                                                                                    |              
|(ii)               |  | Agreement of Purchase and Sale by and between
      Imperial Oil Resources andFletcher Challenge Energy
      Canada, Inc., dated March 13, 1997. (1)                                                                                                                                                              |              
|(iii)              |  | Agreement for Purchase and Sale by and between
      Dynamic Oil Limited andOiltec Resources Ltd., dated
      June 6, 1997. (1)                                                                                                                                                                                   |              
|(iv)               |  | Sour Gas Processing and Transportation Agreement
      by and between ATCO GasServices 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 ProgasLimited, dated November 1,
      1997. (1)                                                                                                                                                                                                |              
|(vi)               |  | Joint Operating Agreement (Shallow Rights)
      by and between Fletcher ChallengeEnergy Canada Inc.
      and Dynamic Oil Limited, dated May 30, 1997.(2)                                                                                                                                                         |              
|(vii)              |  | Joint Operating Agreement (Deep Rights) by
      and between Fletcher ChallengeEnergy Canada Inc.
      and Dynamic Oil Limited, dated May 30, 1997.(2)                                                                                                                                                            |              
|(viii)             |  | Joint Acquisition Agreement St. Albert Area
      by and between Fletcher ChallengeEnergy 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 DynamicOil Limited, dated December
      17, 1997.(2)                                                                                                                                                                                        |              
|(xi)               |  | Management Services Agreement by and between
      Enercap Corporation andDynamic Oil Limited, dated
      December 17, 1997.(2)                                                                                                                                                                                   |              
|(xii)              |  | Demand Debenture and Negative Pledge by Dynamic
      Oil Limited in favor ofEnercap Corporation, dated
      December 17, 1997.(2)                                                                                                                                                                                |              
|(xiii)             |  | Purchasers Lenders Undertaking by and
      among Dynamic Oil Limited, MontrealTrust Company
      of Canada and Enercap Corporation, dated December 17,1997.(2)                                                                                                                                                  |              
|(xiv)              |  | Sweet Gas Processing and Transportation Agreement
      between ATCO GasServices Ltd. and Dynamic Oil &
      Gas Inc., dated December 16, 1998. (3)                                                                                                                                                               |              
|(xv)               |  | Natural Gas Sales Agreement between Producers
      Marketing Ltd. and DynamicOil & Gas, Inc., dated
      November 1, 1999 (re: Dynamics interests atPeavey/Morinville
      in Alberta). (4)                                                                                                                    |              
|(xvi)              |  | Transportation and Processing Agreement between
      ATCO Midstream Ltd. andDynamic Oil & Gas, Inc.
      dated November 1, 2000 (re: Dynamics interests atPeavey/Morinville
      in Alberta). (5)                                                                                                              |              
|(xvii)             |  | Purchase and Sale Agreement between Fletcher
      Challenge Oil & Gas Inc. andDynamic Oil &
      Gas, Inc. et al, dated June 26, 2001 (re: acquisition of Fletchersinterest in St. Albert property by Dynamic, Trioco
      Resources Inc. and EnergyNorth 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 ofFletchers St. Albert interest described above.
      (5) |              

73

---





|(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 OilLimited and Wayne J. Babcock.
      (5)                      |   
|(xxvi)   |  | Overriding Royalty Agreement dated July 13,
      1990 between Dynamic OilLimited and Donzoil Ltd.
      (5)                           |   
|(xxvii)  |  | Overriding Royalty Agreement dated August 31,
      1990 between Dynamic OilLimited and James R. Britton.
      (6)                    |   
|6        |  | Statement re: Earnings Per Share Calculation.
      (5)                                                                                |   
|12.1     |  | Certification Pursuant to 18 U.S.C. Section
      1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley
      Act of 2002. (7) | 76
|12.2     |  | Certification Pursuant to 18 U.S.C. Section
      1350, as Adopted Pursuant to Section906 of the Sarbanes-Oxley
      Act of 2002. (7) | 77

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

|(1 | ) | Form 20-F Annual Report filed on September 30, 1997.
|-- | - | ----------------------------------------------------
|(2 | ) | Form 20-F Annual Report filed on August 18, 1998.   
|(3 | ) | Form 20-F Annual Report filed on September 9, 1999. 
|(4 | ) | Form 20-F Annual Report filed on August 16, 2000.   
|(5 | ) | Form 20-F Annual Report filed on August 15, 2001.   
|(6 | ) | Form 20-F Annual Report filed on August 19, 2002.   
|(7 | ) | Filed herewith.                                     

74

---





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

I CERTIFY THIS IS A COPY OF A
  DOCUMENT FILED ON

FORM 19
  (Section 348)

/s/ John S. Powell

PROVINCE OF BRITISH COLUMBIA

12JOHN
  S. POWELL

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

COMPANY ACT

SPECIAL RESOLUTION

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

|NAME OF COMPANY: | DYNAMIC OIL LIMITED
|---------------- | -------------------

DATE RESOLUTIONS PASSED:             August
  27,1998

Resolution:

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

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

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

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

249601\NAME\0974

75

---





Exhibit 12.1

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

| | 1. | The Report fully complies with the requirements of section
      13(a) or 15(d) of the Securities Exchange Act of 1934; and                                     
| | -- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------
| |    |                                                                                                                                                                 
| | 2. | The information contained in the Report fairly presents,
      in all material respects, the financial condition and results of operations
      of the Company.



/s/ Wayne J. Babcock

Wayne J. Babcock
  President and Chief Executive Officer

Date May 16, 2003



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

76

---





Exhibit 12.2



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

| | 1. | The Report fully complies with the requirements of section
      13(a) or 15(d) of the Securities Exchange Act of 1934; and                                     
| | -- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------
| |    |                                                                                                                                                                 
| | 2. | The information contained in the Report fairly presents,
      in all material respects, the financial condition and results of operations
      of the Company.



/s/ Michael A. Bardell

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

Date May 16, 2003



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

77



---