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|                        | 
|----------------------- | 
|                        | 
|**UNITED
      STATES**

**SECURITIES AND EXCHANGE COMMISSION**


FORM 20-F/A

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

OR

**x****** 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

Commission File Number  0-17551

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

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

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

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

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

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

The number of outstanding shares of our Common Stock outstanding
  as of December 31, 2003 was 22,194,778.

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

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

1

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|                        | 
|----------------------- | 
|                        | 
|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                                       | 35  
|Item 6.           | Directors, Senior Management and Employees                                         | 52  
|Item 7.           | Major Shareholders and Related Party Transactions                                  | 63  
|Item 8.           | Financial Information                                                              | 63  
|Item 9.           | The Offer and Listing                                                              | 63  
|Item 10.          | Additional Information                                                             | 64  
|Item 11.          | Quantitative and Qualitative Disclosures About Market
      Risk                   | 72  
|Item 12.          | Description of Securities Other than Equity Securities                             | 74  
|                  |                                                                                    |     
|Part II.          |                                                                                    |     
|Item 13.          | Defaults, Dividend Arrearages and Delinquencies                                    | 74  
|Item 14.          | Material Modifications to the Rights of Security
      Holders and Use of Proceeds | 74  
|Item 15.          | Controls and Procedures                                                            | 75  
|Item 16(A).       | Audit Committee Financial Expert                                                   | 75  
|Item 16(B).       | Code of Ethics                                                                     | 75  
|Item 16(C).       | Principal Accountant Fees and Services                                             | 75  
|Item 16(D).       | Exemption from the Listing Standards for Audit Committees                          | 75  
|Item 16(E).       | Purchases of Equity Securities by the Issuer and
      Affiliated Purchasers       | 75  
|                  |                                                                                    |     
|Part III.         |                                                                                    |     
|Item 17.          | Financial Statements                                                               | 76  
|Item 18.          | Financial Statements                                                               | 76  
|Item 19.          | Exhibits                                                                           | 76  

2

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|                        | 
|----------------------- | 
|                        | 
|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 Lower Mannville gas formation of lower Cretaceous Age
        about 124 millions years of age.                                                                                                                                                                                                                                                                                                                                                                                                                     
|Bbl or Barrel                     | 42 U.S.
        gallons liquid volume of crude oil or natural gas liquids.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|Bcf                               | Billion
        cubic feet of gas. Usual expression of proved reserve gas volume.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|Belly River
      formation       | Late
        Cretaceous Age sandstones and shales deposited from 75 to 84 million years
        ago.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|Blairmore formation               | Formation
        encompassing clastic sediments deposited in the Early Cretaceous Age from
        about 100 to 120 million years ago.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|Bluesky formation                 | Sandstones
        of the lower Cretaceous Age, about 112 million years old, occurring in
        Northern Alberta and NE BC.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|boe                               | Barrels
        of Oil Equivalent. Generally one barrel of oil equals six mcf of gas.
        Allows reserves of oil and gas to be added together.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|boe/d                             | An expression
        of barrels of oil equivalent produced per day.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|Carbonates                        | Rocks
        composed predominantly of Calcium Carbonate (CaCO3).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|Condensate                        | A mixture
        comprising pentanes and heavier hydrocarbons recovered as a liquid from
        field separators, scrubbers or other gathering facilities or at the inlet
        of a processing plant before the gas is processed.                                                                                                                                                                                                                                                                                                                                                                                              
|Cretaceous Age                    | Rocks
        from 144 million to 66.4 million years of age.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|Crown royalty                     | An amount
        payable to the government of the applicable Canadian province in relation
        to the production of petroleum, natural gas or related hydrocarbons from
        an oil or gas well located on Crown lands.                                                                                                                                                                                                                                                                                                                                                                                                     
|Crude oil                         | A mixture,
        consisting mainly of pentanes and heavier hydrocarbons that may contain
        sulphur compounds, that is liquid at the conditions under which its volume
        is measured or estimated, but excluding such liquids obtained from the
        processing of natural gas.                                                                                                                                                                                                                                                                                                                                     
|Debolt                            | From
        the Mississipian Age, approximately 340 million years old, and is comprised
        most of shales that are separated by regional disconformities.                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|Depletion                         | The
        reduction in petroleum reserves due to production.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Development
      or developed    | Refers
        to the phase in which a proven oil or gas field is brought into production
        by drilling and completing production wells and the wells, in most cases,
        are connected to a petroleum gathering system.                                                                                                                                                                                                                                                                                                                                                                                                  
|Devonian Age                      | Rocks
        from 408 million to 360 million years of age.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|Discovery                         | The
        location, learned through drilling of a well, where there exists an accumulation
        of gas, condensate or oil reserves. The size of the reserves may be estimated
        but not precisely quantified and may or may not be commercially economic,
        depending on a number of factors.                                                                                                                                                                                                                                                                                                                      
|Drill stem test                   | A method
        of packing off the pressure of drilling mud weight to allow a prospective
        oil or gas formation to flow into the drill stem pipe. Drill stem test
        results assist in evaluating the potential of the zone to flow or to be
        pumped commercially.                                                                                                                                                                                                                                                                                                                                              
|Dry hole                          | A well
        drilled without finding commercially economic quantities of hydrocarbons.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|Ellerlsie zone
      or formation | A name
        applied to a group of sandstones that are clear and Quartzose with good
        porosity and permeability for oil and gas about 124 millions years of
        age.                                                                                                                                                                                                                                                                                                                                                                                                                                                   
|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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        

3

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| | 
| | 
| | 

|Formation | A
      reference to a group of rocks of the same age extending over a substantial
      area of a basin.
|--------- | ---------------------------------------------------------------------------------------------------------

|Freehold royalty         | An amount payable to
        a mineral rights holder in relation to the production of petroleum, natural
        gas or related hydrocarbons from an oil or gas well located on non-Crown
        lands.                                                                                                                                                       
|------------------------ | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|GAAP                     | Generally accepted accounting
        principles.                                                                                                                                                                                                                                                                                                              
|Geology                  | The science relating to the
        history and development of the Earth.                                                                                                                                                                                                                                                                                      
|Glauconite               | A sand group from the upper
        Mannville formation (lower Cretaceous Age) about 110 million years ago
        with a green mineral constituent.                                                                                                                                                                                                           
|Gross acres              | The total acreage in which
        the Company has an interest.                                                                                                                                                                                                                                                                                                
|Hackett formation        | A sand package that occurs
        at the base of the Lower Mannville gas formation (lower Cretaceous Age),
        118 to 120 million years old.                                                                                                                                                                                                              
|Hectare                  | A land measurement equaling
        2.471 acres.                                                                                                                                                                                                                                                                                                               
|Horizontal well          | A vertical well bore that
        is gradually deviated (usually horizontally to 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 Upper Devonian Age formation, about 367 to 369 million years
        old. The Jean Marie is found in NE British Columbia and is the stratigraphic
        equivalent to the lower Nisku formation in Alberta.                                                                                              
|kilometer                | A measurement of distance
        equaling 0.621 miles or 3,281 feet.                                                                                                                                                                                                                                                                                          
|Leduc D-3 formation      | A reefal carbonate reservoir
        found within the Upper Devonian Age formation, about 369 to 373 million
        years old. These ancient Leduc reefs were the initial target for oil and
        gas exploration in Alberta. Leduc No. 1, approximately 30 km. South of
        St. Albert, was the discovery well for conventional oil in Western Canada.
|Logs                     | Recordings from electrical
        and radioactive source devices that are run down wellbores to measure
        petrophysical properties of the adjacent 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.                                                                                                                                                                                                                       
|Mannville                | From the early Cretaceous
        period, approximately 110 million years old and represents a major episode
        of subsidence and sedimentation.                                                                                                                                                                                                          
|Meter                    | A physical measurement equaling
        3.281 feet.                                                                                                                                                                                                                                                                                                            
|Mineral taxes (freehold) | An amount levied by the government
        of Alberta in relation to the production of petroleum, natural gas or
        related hydrocarbons from an oil or gas well located on non-government
        (freehold) lands in Alberta.                                                                                                                           
|Mississipian Age         | Rocks from 360 to 325 million
        years of age.                                                                                                                                                                                                                                                                                                            
|Mmcf                     | 1,000,000 cubic feet of natural
        gas.                                                                                                                                                                                                                                                                                                                   
|mmcf/d                   | 1,000,000 cubic feet of natural
        gas production per day. Usually used to express the production rate of
        a gas well or group of gas wells.                                                                                                                                                                                                       
|NYMEX                    | New York Mercantile Exchange,
        the largest physical commodity exchange in the world.                                                                                                                                                                                                                                                                    
|Natural gas              | The lighter hydrocarbons and
        associated non-hydrocarbon substances occurring naturally in an underground
        reservoir, which under atmospheric conditions are essentially a gas, but
        that may contain liquids.                                                                                                                            
|NGLs                    | Natural gas liquids. Hydrocarbon
        components recovered from raw natural gas as liquids by processing through
        extraction plants or recovered from field separators, scrubbers or other
        gathering facilities. These liquids include the hydrocarbon components
        ethane, propane, butane and pentane plus, or combinations thereof. 
|Net acres                | The percentage of gross acreage
        in which the Company has a working interest.                                                                                                                                                                                                                                                                           
|Nisku D-2 formation      | A reefal carbonate reservoir
        in the Winterburn Group of the upper Devonian Age, about 367 to 369 million
        years old. The Nisku is found exclusively within Alberta but it is a stratigraphic
        equivalent to the Jean Marie formation in British Columbia.                                                                                
|Ostracod zone            | Rocks from the lower Cretaceous
        Age approximately 119 million years ago comprised of sandstones and marlstones
        that contain a small fossil named Ostracod.                                                                                                                                                                                     

4

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| | 
| | 
| | 

|Ostracod well | A
      gas well capable of producing commercially from the lower Cretaceous Age
      Ostracod zone.
|------------- | -----------------------------------------------------------------------------------------------------

|Operator                            | That
        party to a joint venture agreement whose responsibility it is to carry
        out all exploratory, development, maintenance and record-keeping duties
        on behalf of other joint venture partners in relation to hydrocarbon extraction
        on the joint-ventured lands.                                                                                                                                                                                              
|----------------------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Overriding royalty                  | An amount
        payable to a third party other than Crown or freehold royalties in relation
        to the production of petroleum, natural gas or related hydrocarbons from
        an oil or gas well located on lands in which the interest of the third
        party usually arises out of a separate agreement.                                                                                                                                                                       
|Pentanes                            | A hydrocarbon
        by-product of natural gas generally referred to as condensate that is
        of the paraffin series having a chemical formula of C5H12and
        having all its carbon atoms joined in a straight chain.                                                                                                                                                                                                                                                              
|Permeability                        | Capacity
        of a rock for transmitting a fluid.                                                                                                                                                                                                                                                                                                                                                                                                                                          
|Permit or licence
      area        | An area
        that is granted for a prescribed period of time for exploration, development
        or production under specific contractual or legislative conditions.                                                                                                                                                                                                                                                                                                                      
|Pipeline                            | A system
        of interconnected pipes that gather and transport hydrocarbons from a
        well or field to a processing plant or to a facility that is built to
        take the hydrocarbons for further transport, such as a gas liquefaction
        plant.                                                                                                                                                                                                                           
|Proved reserves                     | Those
        reserves estimated as recoverable with current technology and under existing
        economic conditions, from that portion of a reservoir that can be reasonably
        evaluated as economically productive through analysis of drilling, geological,
        geophysical and engineering data. This includes the reserves to be obtained
        by enhanced recovery processes demonstrated to be economically and technically
        successful in the subject reservoir.
|Quartzose                           | Rocks
        composed of mostly quartz.                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|Raw gas                             | Gaseous
        effluent from a wellhead or pipeline that is not processed. Contains water
        vapor, carbon dioxide, nitrogen and possibly hydrogen sulphide (H2S)
        gas.                                                                                                                                                                                                                                                                                                          
|Reservoir rock                      | Porous
        limestones, dolomites or sandstones that can trap oil and/or gas in interconnected
        holes, like a sponge.                                                                                                                                                                                                                                                                                                                                                               
|Royalty                             | A stated
        or determinable percentage of the proceeds received from the sale of hydrocarbons
        calculated as prescribed in applicable legislation or in the agreement
        with the royalty holder.                                                                                                                                                                                                                                                                            
|Seals                               | Impermeable
        barriers to hydrocarbon flow such as shale, lime muds, salt or anhydrite.
        Seismic A geophysical technique using low frequency sound waves to determine
        the subsurface structure of sedimentary rocks.                                                                                                                                                                                                                                                     
|Slave Point                         | From
        the middle Devonion Age, approximately 375 million years old and is restricted
        to open-marine carbonate, dominated by shales and argillaceous carbonates.                                                                                                                                                                                                                                                                                                                
|Sour gas                            | Raw
        gas with an amount of hydrogen sulphide (H2S) gas above pipeline
        requirements of 10 parts H2S per million raw gas.                                                                                                                                                                                                                                                                                                                                                        
|Source rock                         | Usually
        shales and clays with a high carbon content deposited in a marine environment.                                                                                                                                                                                                                                                                                                                                                                                                
|Sweet gas                           | Natural
        gas containing no hydrogen sulphide (H2S) gas.                                                                                                                                                                                                                                                                                                                                                                                                                                
|Stabilized absolute
      open flow | The
        maximum rate of gas production that a wellhead will produce assuming no
        backpressure when the well is stable.                                                                                                                                                                                                                                                                                                                                                             
|Tertiary sediment                   | Soft
        rock of sands, clays, coals and siltstones from 66.4 to 1.6 million years
        old.                                                                                                                                                                                                                                                                                                                                                                                           
|Triassic Age                        | Rocks
        from 245 to 208 million years of age.                                                                                                                                                                                                                                                                                                                                                                                                                                           
|Undeveloped                         | Prior
        to the time in which a proven oil or gas field is brought into production
        by drilling and completing production wells.                                                                                                                                                                                                                                                                                                                                                  
|Vertical well                       | A well
        bore that intersects the section(s) containing hydrocarbons at about 90o.                                                                                                                                                                                                                                                                                                                                                                                                      
|Viking                              | From
        the middle Cretaceous Age, 98  133 Million years old, and is comprised
        of interbedded, predominatly marine influenced sandstones and shales.                                                                                                                                                                                                                                                                                                                            
|Viking gas well                     | A well
        capable of commercial gas production from the upper Cretaceous Age Viking
        formation sands deposited about 98 million years ago.                                                                                                                                                                                                                                                                                                                                        
|Wabamun D-1
      formation         | Cyclical
        ramp carbonates deposited approximately 360  367 million years ago
        during the upper Devonian Age period.                                                                                                                                                                                                                                                                                                                                                            
|Working interest                    | Those
        lands in which the Company receives its share acreage of net production
        revenues.                                                                                                                                                                                                                                                                                                                                                                                       

5

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|              | 
|------------- | 
|              | 
|Part
      I.

THIS ANNUAL REPORT AMENDS OUR ANNUAL REPORT ON FORM 20-F FILED
  ON MAY 19, 2004. THE ONLY DIFFERENCE IN THIS REPORT IS THAT IT INCLUDES MAPS
  OF OUR VARIOUS PROPERTIES THAT, DUE TO FILE SIZE DIFFICULTIES, WERE NOT INCLUDED
  IN THE PREVIOUS REPORT.

The year covered by this annual report, Fiscal 2003, coincides
  with the calendar year and is the first full year since we changed our fiscal
  year end to December 31 from March 31. Prior to this filing, our most recently
  filed annual report covered the nine-month period from April 1, 2002 to December
  31, 2002. In this report, we may refer to the 12-month period ended December
  31, 2003 as Fiscal 2003, the nine-month period ended December 31,
  2002 as Nine-Month Fiscal Transition 2002, the 12-month periods
  ended March 31, 2002 and 2001 as Fiscal 2002 and Fiscal 2001,
  respectively, and the 12-month period ending December 31, 2004 as Fiscal
  2004.

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

Item 1. Identity of Directors, Senior Management and Advisers

Not applicable.

Item 2. Offer Statistics and Expected Timetable

Not applicable.

Item 3. Key Information

Selected Financial Data

The following tables summarize certain of our financial information that
  is derived from and should be read in conjunction with our Financial Statements
  and Item 5  Operating and Financial Review and Prospects included
  elsewhere in this Report. The selected financial data has been prepared in accordance
  with Canadian Generally Accepted Accounting Principles (Canadian GAAP). The
  Financial Statements and the notes thereto included pursuant to Item 17 of this
  Report are also prepared under Canadian GAAP. Included in Note 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
  Report, all references to dollars are in Canadian dollars.

Certain of the comparative figures have been restated to conform to the
  current periods presentation as described in Note 3 to the Financial Statements.

|                             | As at    |   | As at    |   |                |   |        |   |         |  
|---------------------------- | -------- | - | -------- | - | -------------- | - | ------ | - | ------- | -
|                             | December |   | December |   |                |   |        |   |         |  
|                             | 31       |   | 31       |   | As at March 31 |  
|($ 000s)                    | 2003     |   | 2002     |   | 2002           |   | 2001   |   | 2000    |  
|Balance Sheets               |          |   |          |   |                |   |        |   |         |  
|Working capital (deficiency) | (19,313  | ) | (16,818  | ) | (13,281        | ) | 1,969  |   | (3,716  | )
|Total assets                 | 64,768   |   | 44,227   |   | 37,732         |   | 29,991 |   | 18,811  |  
|Current liabilities          | 26,632   |   | 23,729   |   | 19,625         |   | 6,210  |   | 7,717   |  
|Long-term liabilities        | 1,588    |   | 1,087    |   | 1,082          |   | 540    |   | 402     |  
|Deferred gain on sale        | -        |   | -        |   | 109            |   | 340    |   | 652     |  
|Future income tax liability  | 5,618    |   | 844      |   | -              |   | 2,955  |   | -       |  
|Net assets                   | 30,931   |   | 18,568   |   | 16,916         |   | 19,947 |   | 10,040  |  
|Share capital                | 27,747   |   | 20,721   |   | 20,915         |   | 20,642 |   | 20,420  |  
|Retained Earnings (deficit)  | 2,825    |   | (2,153   | ) | (4,025         | ) | (695   | ) | (10,379 | )

6

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| | 
| | 
| | 

|                                           |  |        |  | Nine-Month |  |        |   |        |  |       
|------------------------------------------ |  | ------ |  | ---------- |  | ------ | - | ------ |  | ------
|                                           |  |        |  | Fiscal     |  |        |   |        |  |       
|                                           |  | Fiscal |  | Transition |  | Fiscal |   | Fiscal |  | Fiscal
|($ 000s, except per share data)           |  | 2003   |  | 2002       |  | 2002   |   | 2001   |  | 2000  
|Statements of Operations                   |  |        |  |            |  |        |   |        |  |       
|Gross revenues                             |  | 46,848 |  | 24,123     |  | 26,402 |   | 34,463 |  | 15,770
|Gross revenues less royalties              |  |        |  |            |  |        |   |        |  |       
|and production costs                       |  | 27,499 |  | 13,309     |  | 14,215 |   | 20,524 |  | 7,438 
|Cash flow from operations (1)              |  | 23,097 |  | 10,810     |  | 11,337 |   | 18,168 |  | 5,634 
|Cash flow per share, basic ($)             |  | 1.08   |  | 0.53       |  | 0.56   |   | 0.91   |  | 0.29  
|Cash flow per share, diluted ($)           |  | 1.05   |  | 0.53       |  | 0.55   |   | 0.84   |  | 0.26  
|Earnings (loss) before taxes               |  | 7,189  |  | 3,186      |  | (5,259 | ) | 14,449 |  | 2,871 
|Net earnings (loss)                        |  | 4,978  |  | 2,004      |  | (3,412 | ) | 9,714  |  | 4,079 
|Common shares  weighted avg. (# 000s)    |  | 21,394 |  | 20,357     |  | 20,365 |   | 19,938 |  | 19,710
|Common shares  outstanding (# 000s)      |  | 22,195 |  | 20,273     |  | 20,462 |   | 20,146 |  | 19,848
|Net (loss) earnings per share, basic ($)   |  | 0.23   |  | 0.10       |  | (0.17  | ) | 0.49   |  | 0.21  
|Net (loss) earnings per share, diluted ($) |  | 0.23   |  | 0.10       |  | (0.17  | ) | 0.48   |  | 0.20  

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

|                                    |  |             |   | Nine-Month      |   |             |  |             |   |             | 
|----------------------------------- |  | ----------- | - | --------------- | - | ----------- |  | ----------- | - | ----------- | 
|($000s)                            |  |             |   | Fiscal          |   |             |  |             |   |             | 
|                                    |  | Fiscal 2003 |   | Transition 2002 |   | Fiscal 2002 |  | Fiscal 2001 |   | Fiscal 2000 | 
|Cash flow from operating activities |  |             |   |                 |   |             |  |             |   |             | 
|(GAAP measure)                      |  | 28,294      |   | 11,457          |   | 9,779       |  | 19,264      |   | 4,670       | 
|Changes in non-cash working capital |  |             |   |                 |   |             |  |             |   |             | 
|(GAAP measure)                      |  | (5,197      | ) | (647            | ) | 1,558       |  | (1,096      | ) | 964         | 
|Cash flow from operations           |  |             |   |                 |   |             |  |             |   |             | 
|(non-GAAP measure)                  |  | 23,097      |   | 10,810          |   | 11,337      |  | 18,168      |   | 5,634       | 

7

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|                                                               | 
|-------------------------------------------------------------- | 
|                                                               | 
|Selected
      Financial Data Presented According to U.S. GAAP

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

|                              | As at       |  | As at       |   |                |   |        |   |         |  
|----------------------------- | ----------- |  | ----------- | - | -------------- | - | ------ | - | ------- | -
|                              | December 31 |  | December 31 |   | As at March 31 |  
|($ 000s)                     | 2003        |  | 2002        |   | 2002           |   | 2001   |   | 2000    |  
|                              |             |  |             |   |                |   |        |   |         |  
|Balance Sheets                |             |  |             |   |                |   |        |   |         |  
|Future income tax asset       | -           |  | -           |   | 371            |   | -      |   | 242     |  
|Future income tax liability   | -           |  | 541         |   | -              |   | 3,532  |   | -       |  
|                              |             |  |             |   |                |   |        |   |         |  
|Natural gas and oil interests | 56,902      |  | 36,236      |   | 30,150         |   | 21,679 |   | 13,721  |  
|Share capital *               | 28,721      |  | 21,694      |   | 21,883         |   | 21,610 |   | 21,368  |  
|Retained earnings (deficit)   | 1,331       |  | (3,636      | ) | (5,422         | ) | (2,356 | ) | (11,473 | )

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

|                                        |        |   | Nine-Month |   |        |   |        |   |        |  
|--------------------------------------- | ------ | - | ---------- | - | ------ | - | ------ | - | ------ | -
|($ 000s)                               |        |   | Fiscal     |   |        |   |        |   |        |  
|                                        | Fiscal |   | Transition |   | Fiscal |   | Fiscal |   | Fiscal |  
|                                        | 2003   |   | 2002       |   | 2002   |   | 2001   |   | 2000   |  
|Net earnings (loss) under               |        |   |            |   |        |   |        |   |        |  
|Canadian GAAP                           | 4,978  |   | 2,004      |   | (3,412 | ) | 9,714  |   | 4,079  |  
|Amortization and depletion              | -      |   | (65        | ) | (141   | ) | -      |   | -      |  
|Accretion of asset retirement           |        |   |            |   |        |   |        |   |        |  
|obligation                              | -      |   | 40         |   | 36     |   | -      |   | -      |  
|Options issued for services             | -      |   | (3         | ) | -      |   | (20    | ) | -      |  
|Write-downs on natural gas and oil      |        |   |            |   |        |   |        |   |        |  
|properties                              | (125   | ) | (209       | ) | (141   | ) | -      |   | (145   | )
|Income taxes                            | -      |   | -          |   | 709    |   | (577   | ) | -      |  
|Net earnings (loss) before cumulative   |        |   |            |   |        |   |        |   |        |  
|effect of change in accounting          |        |   |            |   |        |   |        |   |        |  
|principle under
      U.S. GAAP         | 4,853  |   | 1,767      |   | (2,949 | ) | 9,117  |   | 3,934  |  
|Cumulative effect of change in          |        |   |            |   |        |   |        |   |        |  
|accounting principle, net of            |        |   |            |   |        |   |        |   |        |  
|applicable
      taxes                  | 133    |   | -          |   | -      |   | -      |   | -      |  
|Net earnings (loss) under               |        |   |            |   |        |   |        |   |        |  
|U.S. GAAP after cumulative effect       |        |   |            |   |        |   |        |   |        |  
|of change in
      accounting principle | 4,986  |   | 1,767      |   | (2,949 | ) | 9,117  |   | 3,934  |  
|Net earnings (loss) per common share    |        |   |            |   |        |   |        |   |        |  
|under U.S. GAAP, before change in       |        |   |            |   |        |   |        |   |        |  
|accounting policy                       |        |   |            |   |        |   |        |   |        |  
|basic                                   | 0.23   |   | 0.09       |   | (0.14  | ) | 0.46   |   | 0.20   |  
|diluted                                 | 0.22   |   | 0.09       |   | (0.14  | ) | 0.45   |   | 0.19   |  
|Net earnings (loss) per common share    |        |   |            |   |        |   |        |   |        |  
|under U.S. GAAP, after change in        |        |   |            |   |        |   |        |   |        |  
|accounting policy                       |        |   |            |   |        |   |        |   |        |  
|basic                                   | 0.23   |   | 0.09       |   | (0.14  | ) | 0.46   |   | 0.20   |  
|diluted                                 | 0.23   |   | 0.09       |   | (0.14  | ) | 0.45   |   | 0.19   |  

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.

8

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|                     | 
|-------------------- | 
|                     | 
|Exchange
      Rates

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

Exchange Rates for Canadian Versus U.S. Dollars

The exchange rate as of May 5, 2004 was CDN $1.37 per U.S. $1.00.

|(High/low rates for latest six months) | High |  | Low  | 
|-------------------------------------- | ---- |  | ---- | 
|April, 2004                            | 1.37 |  | 1.31 | 
|March, 2004                            | 1.35 |  | 1.31 | 
|February, 2004                         | 1.34 |  | 1.31 | 
|January, 2004                          | 1.33 |  | 1.27 | 
|December, 2003                         | 1.34 |  | 1.29 | 
|November , 2003                        | 1.34 |  | 1.30 | 

|                                                    | Average ($) | 
|--------------------------------------------------- | ----------- | 
|For the twelve-month period ended December 31, 2003 | 1.40        | 
|For the nine-month period ended December 31, 2002   | 1.56        | 
|For the twelve-month period ended March 31, 2002    | 1.57        | 
|For the twelve month period ended March 31, 2001    | 1.50        | 
|For the twelve month period ended March 31, 2000    | 1.47        | 

Capitalization and Indebtedness

Not applicable.

Reasons for the Offer and Use of Proceeds

Not applicable.

Risk Factors

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

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.

9

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| | 
| | 
| | 
|



Availability of Natural Gas Supply

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

Dependence on Third-Party Pipelines

In Fiscal 2003, substantially all our sales of natural gas were effected
  through deliveries to local third-party gathering systems to processing plants
  in Alberta owned by ATCO Midstream Ltd. and Northwestern Utilities Limited.
  In addition, we rely on access to interprovincial pipelines for the sale and
  distribution of substantially all of our gas. As a result, a curtailment of
  our sale of natural gas by pipelines or by third-party gathering systems, an
  impairment of our ability to transport natural gas on interprovincial pipelines
  or a material increase in the rates charged to us for the transportation of
  natural gas by reason of a change in federal or provincial regulations or for
  any other reason, could have a material adverse effect upon us. In such event,
  we would have to obtain other transportation arrangements or we would have to
  construct alternative pipelines. There can be no assurance that we would have
  economical transportation alternatives or that it would be feasible for us to
  construct pipelines. In the event such circumstances were to occur, our field
  netbacks from the affected wells would be suspended until, and if, such circumstances
  could be resolved.

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

We first experienced earnings in Fiscal 1999 of $1,211,638. In Fiscal 2000
  and Fiscal 2001, we reported earnings of $4,078,577 and $9,714,030 respectively
  and in Fiscal 2002, we had a loss of $3,412,452. In Nine-Month Fiscal Transition
  2002, and in Fiscal 2003 we again reported earnings of $2,004,306 and $4,978,302,
  respectively. As at December 31, 2003, we had an accumulated retained earnings
  of $2,825,311. 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 professional efforts and expertise
  of our President & Chief Executive Officer, Wayne J. Babcock, our Vice President
  & Chief Operating Officer, Donald K. Umbach, our Vice President of Production,
  David G. Grohs and our Chief Financial Officer & Corporate Secretary, Michael
  A. Bardell. The loss of the services of any of these persons could have a material
  adverse effect on us.

10

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|                                                    | 
|--------------------------------------------------- | 
|                                                    | 
|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                 During Fiscal 2003, our core property at St. Albert, Alberta, contributed
  85% of our total production. While the St. Albert property 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 the combination of cash flow from operations, our bank credit
  facility and a recently-announced private placement, to support land acquisitions,
  drilling operations, facilities construction and general /administration costs
  in Fiscal 2004. If warranted, we would seek term debt to finance construction
  of long-life facilities and equity to fuel accelerated, project exploration
  plans. There can be no assurance that we will be able to raise additional capital
  in light of factors such as the market demand for our securities, the state
  of financial markets for independent oil companies (including the markets for
  debt), oil and gas prices and general market conditions. (See Item 5 - "Operating
  and Financial Review and Prospects" for a discussion of our capital budget).

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

11

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| | 
| | 
| | 
|




Operating Hazards and Uninsured Risks

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

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

Drilling Plans Subject to Change

This Report includes descriptions of our future drilling plans with respect
  to our prospects. A prospect is a property on which our geoscientists have identified
  what they believe, based on available seismic and geological information, to
  be indications of hydrocarbons. Our prospects are in various stages of review.
  Whether or not we ultimately drill a prospect may depend on the following factors:
  receipt of additional seismic data or reprocessing of existing data; material
  changes in oil or gas prices; the costs and availability of drilling equipment;
  success or failure of wells drilled in similar formations or which would use
  the same production facilities; availability and cost of capital; changes in
  the estimates of costs to drill or complete wells; our ability to attract other
  industry partners to acquire a portion of the working interest to reduce exposure
  to costs and drilling risks; decisions of our joint working interest owners;
  and 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 from operations and
  net earnings, are highly dependent upon our level of success in finding or acquiring
  additional economically recoverable reserves. The business of exploring for,
  developing and acquiring reserves is capital intensive. To the extent cash flow
  from operations is reduced and external sources of capital become limited or
  unavailable, our ability to make the necessary capital investment to maintain
  or expand our asset base of natural gas and oil reserves could be materially
  impaired.

Estimating of Reserves and Future Net Cash Flows Risk

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

| | • | reservoir characteristics based on variable geological, geophysical and
      engineering assessments;
| | - | ------------------------------------------------------------------------------------------------------
| | • | future rates of production based on historical draw-down rates;                                       

12

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| | 
| | 
| | 

| | • | future net cash flows based on commodity price/quality
        assumptions, production costs, taxes and investment decisions;
| | - | -----------------------------------------------------------------------------------------------------------------------------
| | • | recoverable reserves based on estimated future net
        cash flows; and                                                   
| | • | compliance expectations based on assumed federal,
        provincial and environmental laws and regulations.                 

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

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

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 asset retirement obligations,
  we recognized $0.1 million in our Statement of Operations and Deficit during
  Fiscal 2003, bringing our total recognized amount in our Fiscal 2003 Balance
  Sheet to $1.6 million. We engage independent engineering consultants to assist
  in assessing our total asset retirement obligations related to removal and clean-up
  costs. While we cannot predict their ultimate cost, we currently estimate the
  future cost to clean up all our operating facilities to be $3.3 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.

13

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|                    | 
|------------------- | 
|                    | 
|Kyoto Protocol Risk

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

Interruption From Severe Weather

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

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

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.

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

14

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|                                                           | 
|---------------------------------------------------------- | 
|                                                           | 
|Capital Expenditures Over the Past Three Reporting Periods

Over the past three reporting periods our capital expenditures aggregated
  $66.4 million, an amount that is broken down by reporting period and spending
  classification in the following table:

|                               |        |  | Nine- Month |  |             |  |              | 
|------------------------------ | ------ |  | ----------- |  | ----------- |  | ------------ | 
|                               |        |  | Fiscal      |  |             |  |              | 
|                               | Fiscal |  | Transition  |  |             |  | Three-Fiscal | 
|($000s)                       | 2003   |  | 2002        |  | Fiscal 2002 |  | Period Total | 
|Land acquisitions              | 5,103  |  | 2,568       |  | 12,560      |  | 20,231       | 
|Gross overriding royalty       |        |  |             |  |             |  |              | 
|interest
      acquisition (1) | 9,711  |  | -           |  | -           |  | 9,711        | 
|Drilling, completions and      |        |  |             |  |             |  |              | 
|equipping:                     |        |  |             |  |             |  |              | 
|Exploratory                    | 5,717  |  | 4,914       |  | -           |  | 10,631       | 
|Development                    | 9,460  |  | 4,232       |  | 7,678       |  | 21,370       | 
|Facilities and pipelining      | 1,448  |  | 780         |  | 1,757       |  | 3,985        | 
|Other                          | 308    |  | 84          |  | 116         |  | 508          | 
|Total                          | 31,747 |  | 12,578      |  | 22,111      |  | 66,436       | 

|(1) | On July 7, 2003, we repurchased from three of our
        officers their gross overriding royalty interests for and aggregate of
        $6,516,000. The aggregate purchase price was paid by the issuance of 1,050,666
        of our common stock and the payment of $1,000,000 in cash. The repurchased
        overriding royalty interest of $9,711,000 shown above is comprised of
        the aggregate repurchase price of $6,516,000 paid to the sellers, plus
        the related future income taxes of $3,195,308 which require recognition
        in accordance with current accounting rules under Canadian GAAP. (For
        further details, see Note 7[d] to our Financial Statements under Item
        17 to this Report).
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In the table above, the total three-year aggregated amount of $66.4 million
  is itemized further by reporting period as follows:

Fiscal 2003 
                  During Fiscal 2003, our capital expenditures totaled $31.7 million, an amount
  that is broken down by spending classification and property in the following
  table:

|                             | Land and Gross |  |               |  |                |  |       |  |        | 
|---------------------------- | -------------- |  | ------------- |  | -------------- |  | ----- |  | ------ | 
|                             | Overriding     |  | Drilling,     |  |                |  |       |  |        | 
|                             | Royalty        |  | Completions   |  | Facilities and |  |       |  |        | 
|($ 000s)                    | Acquisitions   |  | and Equipping |  | Pipelining     |  | Other |  | Total  | 
|Alberta                      |                |  |               |  |                |  |       |  |        | 
|St. Albert                   | 49             |  | 5,951         |  | 882            |  | -     |  | 6,882  | 
|Wimborne                     | 1,694          |  | 626           |  | -              |  | -     |  | 2,320  | 
|Halkirk                      | -              |  | 537           |  | 27             |  | -     |  | 564    | 
|Peavey/Morinville            | -              |  | 160           |  | 44             |  | -     |  | 204    | 
|Other Alberta                | -              |  | 42            |  | 1              |  | -     |  | 43     | 
|Total Alberta                | 1,743          |  | 7,316         |  | 954            |  | -     |  | 10,013 | 
|Cypress/Chowade              | 2,779          |  | 5,689         |  | 494            |  | -     |  | 8,962  | 
|Orion                        | 581            |  | 2,172         |  | -              |  | -     |  | 2,753  | 
|Total British Columbia       | 3,360          |  | 7,861         |  | 494            |  | -     |  | 11,715 | 
|Gross overriding royalty     |                |  |               |  |                |  |       |  |        | 
|acquisition and other assets | 9,711          |  | -             |  | -              |  | 308   |  | 10,019 | 
|Total                        | 14,814         |  | 15,177        |  | 1,448          |  | 308   |  | 31,747 | 

Land and Gross Overriding Royalty Acquisitions 
                  During Fiscal 2003, our investment in land increased by $5.1 million in
  the following areas: $2.8 million at Cypress/Chowade (9,740 net acres); $1.7
  million at Wimborne (5,995 net acres); and $0.6 million at Orion (8,545 net
  acres).

Also during Fiscal 2003, we invested $6.5 million in the repurchase of certain
  gross overriding royalty interests (GORR) that previously burdened
  our total current and future corporate production by 3%. The carrying value
  of the repurchase has been adjusted upward by a non-cash amount of $3.2 million,
  as required by Canadian GAAP.

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Drilling, Completions, Equipping, Facilities and Pipelining 
                  During Fiscal 2003, expenditures incurred on drilling, completions, equipping,
  facilities and pipelining totaled $16.6 million. These expenditures were split
  evenly between Alberta and British Columbia, as follows:

Alberta 
                   St. Albert - A total of six wells were drilled, four targeting
  crude oil and two targeting natural gas. All wells were successful and each
  was completed in a single zone. Crude oil completions were in the Nisku D-2
  and the Leduc D-3 formations, while natural gas completions were in the Ostracod
  zone. Upgrades to field compression, salt water injection facilities and our
  crude oil tank farm were also conducted.

Wimborne  During the year, we drilled our first-ever
  tests for natural gas at Wimborne. We drilled two Cretaceous Age wells, one
  of which was successful and completed as a standing gas well.

Halkirk Two development wells targeting natural
  gas in the Viking formation were drilled during the year. One was successful
  and completed as a producing well.

British Columbia 
                   Cypress/ChowadeDuring the year, we participated
  in drilling three natural gas exploration wells, targeting Triassic Age reservoirs.
  All three wells were cased and tied-in. A field compressor was also added.

Nine-Month Fiscal Transition 2002 
                  
  During this period, we invested an aggregate of$12.6 million, $6.2 million
  or 49% of which was spent on Alberta properties and $6.4 million or 51% on British
  Columbia properties. Of the amount invested in Alberta, $5.0 million was for
  land, drilling, completions, equipping and facilities at St. Albert and the
  balance of $1.2 million was for drilling, completions and equipping at Halkirk.
  Of the amount invested in British Columbia, $5.0 million was for drilling, completions
  and equipping at Cypress/Chowade and the balance of $1.4 million was for land
  acquisitions at Orion.

Fiscal 2002 
                  
  During this period, we invested an aggregate of $22.1 million, $7.3 million
  of which was spent at St. Albert for drilling, completions and equipping. The
  balance of $14.8 million was spent mostly to acquire additional working interests
  at St. Albert.

Exploration Expenses Over the Past Three Reporting Periods

Over the past three fiscal reporting periods our exploration expenses aggregated
  $10.2 million, an amount that is broken down by fiscal reporting period and
  spending classification in the following table:

|                           |  |             |  | Nine- Month |  |             |  |              | 
|-------------------------- |  | ----------- |  | ----------- |  | ----------- |  | ------------ | 
|                           |  |             |  | Fiscal      |  |             |  |              | 
|($000s)                   |  |             |  | Transition  |  |             |  | Three-Fiscal | 
|                           |  | Fiscal 2003 |  | 2002        |  | Fiscal 2002 |  | Period Total | 
|Drilling(1)                |  | 1,278       |  | 325         |  | 3,821       |  | 5,424        | 
|Seismic data activity      |  | 2,349       |  | 934         |  | 649         |  | 3,932        | 
|Other                      |  | 439         |  | 187         |  | 176         |  | 802          | 
|Total exploration expenses |  | 4,066       |  | 1,446       |  | 4,646       |  | 10,158       | 

|(1) | We follow the successful efforts method of accounting,
        whereby costs of drilling an unsuccessful well are expensed when it becomes
        known the well did not result in a discovery of proved reserves.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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|                                                                     | 
|Fiscal 2004  Budgeted Capital Expenditures and Exploration Expenses

During Fiscal 2004, our budgeted capital expenditures and exploration expenses
  total $37.1 million, an amount that is broken down by spending classification
  and property in the following table:

|                       |              |  | Drilling,     |  |                |  | Seismic |  |        | 
|---------------------- | ------------ |  | ------------- |  | -------------- |  | ------- |  | ------ | 
|                       | Land         |  | Completions   |  | Facilities and |  | and     |  |        | 
|($ 000s)              | Acquisitions |  | and Equipping |  | Pipelining     |  | Other   |  | Total  | 
|Alberta                |              |  |               |  |                |  |         |  |        | 
|St. Albert             | -            |  | 5,587         |  | 1,256          |  | -       |  | 6,843  | 
|Wimborne               | -            |  | 842           |  | 49             |  | -       |  | 891    | 
|Halkirk                | -            |  | -             |  | 100            |  | -       |  | 100    | 
|Peavey/Morinville      | -            |  | -             |  | -              |  | 256     |  | 256    | 
|Alexander              | -            |  | -             |  | 350            |  | -       |  | 350    | 
|Other                  | 937          |  | -             |  | -              |  | -       |  | 937    | 
|Total Alberta          | 937          |  | 6,429         |  | 1,755          |  | 256     |  | 9,377  | 
|British Columbia       |              |  |               |  |                |  |         |  |        | 
|Cypress/Chowade        | 3,015        |  | 9,169         |  | 8,902          |  | 550     |  | 21,636 | 
|Orion                  | -            |  | 2.988         |  | 300            |  | 1,200   |  | 4,488  | 
|Total British Columbia | 3,015        |  | 12,157        |  | 9,202          |  | 1,750   |  | 26,124 | 
|Contingency            | -            |  | -             |  | -              |  | 1,550   |  | 1,550  | 
|Total                  | 3,952        |  | 18,586        |  | 10,957         |  | 3,556   |  | 37,051 | 

Our Fiscal 2004 capital budget focuses on three primary objectives:

| | • | To continue to optimize production and cash flow
        at our St. Albert property. As our primary producing asset, St. Albert
        contributed 85% of our total production in Fiscal 2003;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | To generate reserve and production growth in 2004
        through the development of drilling opportunities, pipelining and facility
        projects; and                                     
| | • | To establish new core areas for future growth through
        our exploration efforts at Cypress/Chowade, Orion and Wimborne.                                                                  

In total, our budget for Fiscal 2004, is allocated 25% to Alberta, 71% to British
  Columbia and 4% to properties yet to be allocated between the two provinces.

Our 2004 capital and exploration expense program is based on our targeted daily
  average production rates (see Item 5  Outlook for Fiscal 2004),
  and estimated weighted average prices for natural gas ranging from $5.84 to
  $6.95 per mcf and for crude oil from $36.44 to $43.09 per barrel (see Item 5
   Liquidity and Capital Resources  Sources and Uses of Cash).
  While we do not currently anticipate any difficulties in meeting the majority
  of our obligations with cash flows from operations, our bank credit facility
  and our recently-announced private placement, our board of directors may choose
  to modify our spending plans in order to fine-tune our cash flow timing differences
  or seek further equity financing for projects of high impact potential.

Recent Material Events

On April 30, 2004, we entered into a bought-deal private placement with both
  Octagon Capital Corporation as lead underwriter and Raymond James Ltd. Pursuant
  to the terms of the agreement, we have agreed to issue, by way of private placement,
  2,000,000 flow-through common shares at $5.60 each on a firm underwriting basis.
  As well, at the option of the underwriters, exercised at least one business
  day before closing, we have agreed to issue 400,000 non-flow through common
  shares at $4.55 each. If the underwriters exercise their option, the total gross
  proceeds of the offering will be $13,020,000.

Under the Income Tax Act (Canada), the concept of flow-through shares is that
  an investor subscribes for shares of a corporation and the corporation uses
  the subscription funds to incur expenses which it renounces to the investor.
  By virtue of such renunciation, the expenses incurred by the corporation are
  treated as resource expenses of the investor for purposes of the Income Tax
  Act (Canada). Such flow-through shares can be sold only to Canadian residents.

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None of the shares will be offered to U.S. residents and will not be and have
  not been registered under the United States Securities Act of 1933 and may not
  be re-offered or sold in the United States absent registration or an applicable
  exemption from the registration requirement.

Share Repurchases

During the last three reporting periods, we spent an aggregate $0.6 million
  on the repurchase of outstanding common shares, $0.3 million in each of Nine-Month
  Fiscal Transition 2002 and Fiscal 2002. We did not repurchase any shares in
  Fiscal 2003. The number of common shares repurchased was over 0.4 million at
  prices ranging from $1.62 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.

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

| | (i)  | Working Interest (WI): means the percentage
        of undivided interest held by a Joint Operator (i.e. leaseholder) in a
        specific tract of land (i.e. joint lands). The Working Interests held
        by all Joint Operators in any specific tract of joint lands must total
        100%. Each W.I. party is responsible for its WI percentage share of costs
        incurred to conduct "work" (i.e. drilling, seismic, production etc.) on
        the joint lands. Working Interests are always considered to be an active
        interest in the costs, risks and benefits associated with the joint lands
        and operations conducted thereon and the oil or gas produced there from.
| | ---- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |      |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
| | (ii) | Overriding Royalties (ORR): Overriding
        Royalties are a specified share of oil and/or gas as and when produced.
        ORR's are free and clear of costs, risk and expense to the holder of the
        ORR. Usually ORR's are based on gross production and as such are referred
        to as "Gross" Overriding Royalties or GORR's. ORR's are considered a passive
        interest in as much as the holder of an ORR is not subject to any cost,
        risk or expense nor is the ORR holder involved in any decision-making
        with respect to the royalty lands.                                                                                                                      

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

Concentration of Commodities

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

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

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

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

Concentration of Operations

Our main producing property is located at St. Albert, Alberta. Of our total
  production in Fiscal 2003, 85% came from the St. Albert property. The remainder
  originated mainly from seven other fields: Halkirk, Cypress/Chowade, Peavey/Morinville,
  Alexander, Simonette, Stanmore and Westlock. In Nine-Month Fiscal Transition
  2002, 85% of our production came from the St. Albert field, while the remainder
  came from six other fields: Halkirk, Peavey/Morinville, Alexander, Westlock,
  Simonette and Stanmore. In Fiscal 2002, 84% of our production came from the
  St. Albert field, while the remainder originated from five other fields: Peavey/Morinville,
  Halkirk, Westlock, Simonette, 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:

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

Natural Gas, Natural Gas Liquids and Crude Oil Revenue

|                    |                   |  | Nine Month Fiscal     |  |                   | 
|------------------- | ----------------- |  | --------------------- |  | ----------------- | 
|($ 000s)           | Fiscal
      2003 |  | Transition
      2002 |  | Fiscal
      2002 | 
|Natural gas         | 30,649            |  | 17,058                |  | 20,944            | 
|Natural gas liquids | 6,646             |  | 4,012                 |  | 4,442             | 
|Crude oil           | 9,553             |  | 3,053                 |  | 1,016             | 
|Total               | 46,848            |  | 24,123                |  | 26,402            | 

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.

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

Marketing

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

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

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

During Fiscal 2003, we sold 46% of our natural gas to ProGas and 54% into the
  AECO daily spot market. During Nine-Month Fiscal Transition 2002 and Fiscal
  2002, we sold 51% and 53% 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 the 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 2003 Canadian Energy Survey of 2002 Results prepared by PriceWaterhouseCoopers,
  we ranked thirty-third and thirty-ninth 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 commencing
        drilling operations;                                                                          
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | requirements to restrict the substances that can
        be released into the environment in connection with drilling and production
        activities;
| | • | limitations on, or prohibitions to, drilling in protected
        areas such as offshore areas; and                                                     
| | • | requirements to mitigate and remediate the effects
        caused by drilling and production operations.                                                

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|                                | 
|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/Chowade (northeastern B.C.)
|Halkirk           | Westlock         | Orion (northeastern B.C.)          
|Peavey/Morinville | Wimborne         | Fraser Valley (southwestern B.C.)  
|Alexander         | Quirk Creek      |                                    
|Simonette         |                  |                                    

Our total land holdings increased during Fiscal 2003 by 11,177 net acres (29,283
  gross) or 10%. This increase was mainly spread between two key properties, Wimborne,
  Alberta and Cypress/Chowade, British Columbia. Some of the net increase was
  offset with minor land reductions at St. Albert, Halkirk and Peavey/Morinville,
  Alberta. We had significant land reductions at Quirk Creek, Alberta of 2,400
  net acres (4,800 gross). Of our total land holdings, 100,256 net acres (189,290
  gross) or 82% was undeveloped.

|                      | Developed |  | Undeveloped |  | Total   |  | Weighted | 
|--------------------- | --------- |  | ----------- |  | ------- |  | -------- | 
|Area                  | Gross     |  | Net         |  | Gross   |  | Net      | 
|Alberta               |           |  |             |  |         |  |          | 
|St.
      Albert      | 9,308     |  | 6,060       |  | 4,442   |  | 3,150    | 
|Halkirk               | 3,840     |  | 3,456       |  | 2,880   |  | 2,880    | 
|Peavey/Morinville     | 6,787     |  | 4,921       |  | 4,766   |  | 2,954    | 
|Quirk
      Creek     | -         |  | -           |  | 6,560   |  | 3,280    | 
|Wimborne              | 640       |  | 640         |  | 9,035   |  | 8,555    | 
|Other
      (1)       | 3,527     |  | 2,689       |  | 3,340   |  | 3,072    | 
|                      | 24,102    |  | 17,766      |  | 31,023  |  | 23,891   | 
|British Columbia      |           |  |             |  |         |  |          | 
|Cypress/Chowade       | 5,976     |  | 2,564       |  | 39,154  |  | 12,953   | 
|Orion                 | 2,003     |  | 1,335       |  | 64,611  |  | 45,134   | 
|Fraser
      Valley   | -         |  | -           |  | 54,502  |  | 18,278   | 
|                      | 7,979     |  | 3,899       |  | 158,267 |  | 76,365   | 
|Total to Dec 31, 2003 | 32,081    |  | 21,665      |  | 189,290 |  | 100,256  | 
|Total to Dec 31 2002  | 30,170    |  | 20,248      |  | 161,918 |  | 90,496   | 
|Increase (decrease)   | 1,911     |  | 1,417       |  | 27,372  |  | 9,760    | 
|Increase (decrease) % | 6%        |  | 7%          |  | 17%     |  | 11%      | 

|(1) | Includes our Saskatchewan interests, which are too immaterial to warrant
      separate disclosure.
|--- | ---------------------------------------------------------------------------------------------------

Our weighted average working interest of all our Alberta properties was 76%
  versus 48% in British Columbia. In total, our weighted average working interests
  decreased by 3% to 55%, mainly due to a proportionately larger increase in undeveloped
  acreage at Cypress/Chowade having a weighted average working interest of 34%.

Alberta Properties

St.Albert
                  
  St. Albert is located in central Alberta, northwest of the City of Edmonton
  and near the City of St. Albert.

Geological Description 
                  
  The property is comprised of two Devonian Age reef structures, which are associated
  with 16, separate Cretaceous Age natural gas and Devonian Age crude oil pools
  stacked in seven productive formations, four are natural gas and three crude
  oil. For purposes of project identification, we refer to these structures as
  the north pool and the south pool. Historically, the
  property has produced in excess of 22.5 million barrels of crude oil and 109
  billion cubic feet of raw natural gas from both pools. They continue to remain
  prospective for recoverable oil from six established Devonian Age pools in the
  Leduc D-3, Nisku D-2 and Wabamun D-1 formations.

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|              | 
|------------- | 
|              | 
|Land Holdings

SeismicWe own a 37.5% working interest in a proprietary 3D seismic database
  covering 12 square kilometers.

Wells and Facilities                
  We own a 75% working interest in 17 producing gas wells; from a 44% to 77% working
  interest in another four; and a 75% working interest in seven producing oil
  wells. In addition, we own a 75% working interest in one oil battery, one solution
  gas plant, one sour gas compressor, two sweet gas compressors and a 13 kilometer,
  6 sour gas pipeline.

Fiscal 2003 ActivitiesIn the south pool, we drilled three wells targeting remaining Devonian
  Age oil reserves. Two of these wells encountered oil pay in the Leduc D-3 formation
  and one well, while unsuccessful in the Leduc D-3 formation, was later completed
  as a Nisku D-2 formation oil well. In the north pool, we drilled one well also
  targeting remaining Devonian Age oil reserves. While the well was unsuccessful
  in the Leduc D-3 formation, it was later completed as a Nisku D-2 formation
  oil well.

We drilled two successful wells targeting remaining natural gas in the Ostracod
  zone. We were able to minimize surface and environmental impacts by re-entering
  existing well bores in all of our drilling activity. We addressed declining
  reservoir pressures in various sweet gas pools by adding third-party owned compression
  at the nearby Villeneuve and Carbondale gas plants.

Fiscal 2004 Outlook 
                  
  Our budget for Fiscal 2004 focuses on continued optimization of the field. All
  projects are geared toward recovery of remaining crude oil and natural gas reserves
  from known pools. Our development drilling, re-completions and work-overs will
  specifically target the Leduc D-3, and Nisku D-2 oil formations, and the Ostracod
  zone and Belly River formations.

Our investment at St. Albert includes numerous wells and facilities. For this
  reason, we communicate with the public in the area and work closely with government
  regulators.

Halkirk 
                  
  Halkirk is located in central Alberta approximately 168 kilometers northeast
  of Calgary.

Geological Description 
                  
  This area is prospective for multiple, sweet natural gas-bearing Cretaceous
  Age sandstone reservoirs. The primary target for reserves is the Viking formation
  with an average net pay thickness of approximately five meters.

Land Holdings 
                  
  We own 6,336 net acres (6,720 gross) of crown and freehold petroleum and natural
  gas leases for a weighted average working interest of 94%. Of our net acreage,
  45% is undeveloped.

Wells and Facilities 
                  
  We own a 100% working interest in five producing and two standing natural gas
  wells. We also own an 80% working interest before payout (of our initial capital
  expenditures) and a 48% working interest after payout in three producing gas
  wells. All of our natural gas production is processed at the Maple Glen Gas
  Plant under a third-party custom processing agreement.

Fiscal 2003 Activities 
                  
  We drilled one successful infill Viking formation gas well and one unsuccessful
  step-out well. A step-out well is a well drilled near a proven well,
  but located in an unproven area to determine the boundaries of the producing
  formation. We acquired 320 net acres (100%) of new petroleum and natural gas
  rights.

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|------------------- | 
|                    | 
|Fiscal 2004 Outlook




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

Geological Description 
                  
  The area is prospective for multiple Cretaceous Age sandstone reservoirs containing
  natural gas and natural gas liquids. Additional potential exists for crude oil
  and natural gas within deeper Mississippian and Devonian Age carbonate reservoirs.

Land Holdings 
                  
  We own 9,195 net acres (9,675 gross) of petroleum and natural gas rights for
  a weighted average working interest of 95%. Of our total net holdings, 93% is
  undeveloped.

Seismic 
                  
  We own a licensed copy of a high quality, 3D seismic database covering 260 square
  kilometers.

Wells and Facilities 
                  
  We own a 100% working interest in one standing gas well. The property is in
  close proximity to existing natural gas pipelines and processing facilities.

Fiscal 2003 Activities 
                  
  We drilled one successful gas well and one unsuccessful well. We acquired a
  100% working interest in approximately ten new sections (6,475 acres) of crown
  petroleum and natural gas leases.

Fiscal 2004 Outlook 
                  
  Our large 3D seismic database is expected to enhance our long-term exploration
  and development strategy for the area. Through it, we have identified up to
  six exploration targets on our lands, three of which are planned for drilling
  this year.

British Columbia Properties

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

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

Land Holdings 
                  
  We have crown petroleum and natural gas leases over 15,517 net acres (45,130
  gross) for a weighted average working interest of 34%. Of our total net acreage,
  83% is undeveloped.

Seismic 
                  
  We own a licensed copy of a large 2D seismic database and a 100% working interest
  in 15 kilometers of 2D proprietary seismic data.

Wells and Facilities                We
  own between 30% - 50% working interests in two producing gas wells and six standing
  shut-in gas wells, which are currently producing. In five of these eight wells,
  our interest converts from 50% working interest to 30% working interest at payout.
  All of our fiscal 2003 gas production was processed at Cypress Gas Plant under
  a third-party custom processing agreement. A major expansion of pipeline and
  processing facilities is required to develop this area.

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|---------------------- | 
|                       | 
|Fiscal 2003 Activities




Fiscal 2004 Outlook 
                  
  We plan to drill three exploratory outpost wells and three development wells.
  We have budgeted to cover our half of the cost to construct a 30 mmcf/d sour
  gas plant, acid gas injection facilities and a 32 kilometer, 8 diameter
  sales pipeline to Sikanni, British Columbia. The initial leg of the proposed
  8 diameter sales pipeline was scheduled for construction in the first
  quarter. We plan to have three of our six standing shut-in gas wells on stream
  in the first quarter and the remaining three wells on stream later in the year.
  We have seismically identified more than 30 potential exploration and development
  locations on company-owned lands. We plan to continue an aggressive land acquisition
  strategy.

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

A large independent Canadian oil and gas company has referred to the regional
  Devonian Age Jean Marie carbonate reservoir in this area as The Greater
  Sierra Gas Play and has described the area as the largest gas play discovered
  in Western Canada. Orion is a part of this area and is a key element in our
  long-term growth strategy.

Geological Description 
                  
  The area is prospective for natural gas exploration and development in Cretaceous
  Age Bluesky sandstone reservoirs and Mississippian and Devonian Age Debolt,
  Jean Marie and Slave Point formation carbonate reservoirs.

Land Holdings 
                  
  We hold under lease 46,469 net acres (66,614 gross) for a weighted average working
  interest of 70%. Approximately 97% of our net holdings are undeveloped.

Wells and Facilities 
                  
  The property presently has three potential gas wells; one Bluesky formation
  and two Devonian Age Jean Marie formation horizontal wells. All three wells
  are standing awaiting further evaluation. We own a 100% working interest in
  the Bluesky formation and one Devonian Age Jean Marie formation well, a 15%
  gross overriding royalty (before payout) and a 50% working interest (after payout)
  in the other Devonian Age Jean Marie formation well.

Two major pipeline systems terminate at the edge of our property. To the southwest,
  the Duke Energy Pipeline System connects to Fort Nelson for delivery to Washington
  State and to the northeast, the Duke Energy Field Services Pipeline System connects
  to Tooga Compressor Station for delivery to Alberta.

Fiscal 2003 Activities 
                  
  We drilled one horizontal well at 100% working interest to test the Devonian
  Age Jean Marie formation. The well tested gas at rates below commercial quantities
  and is being retained as a potential gas well pending further evaluation.

Fiscal 2004 Outlook 
                  
  We plan to drill two 100% working interest exploration wells; one to test the
  Devonian Age Slave Point formation and one to test the Cretaceous Age Bluesky
  formation. We plan to shoot 90 square kilometers of proprietary 3D seismic data.

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|              | 
|Fraser Valley



Land Holdings 
                  
  Under a joint venture agreement with Conoco Canada Limited, we continue to hold
  a weighted average working interest of 34% in approximately 18,278 net acres
  (54,502 gross) of undeveloped onshore and offshore petroleum and natural gas
  rights associated with Permit 802, a validated British Columbia Exploration
  Permit. Permit 802 is under provincial jurisdiction and includes offshore petroleum
  and natural gas rights in the Georgia Basin, located in the Strait of Georgia
  between the Lower Mainland and Vancouver Island.

Fiscal 2003 Activities 
                  
  We were inactive in the Fraser Valley area during Fiscal 2003.

Fiscal 2004 Outlook 
                  
  Presently, areas offshore are subject to a restricted-access moratorium for
  petroleum and natural gas activities, however, discussions are underway between
  the Provincial and Federal Governments in regards to lifting the moratorium.
  The Provincial Government has indicated its desire to move forward and the Federal
  Government is currently conducting a public review to identify environmental
  and social concerns arising from offshore activities along the Pacific West
  Coast. A final decision is expected in 2004. We have identified through analysis
  of our proprietary onshore 2D seismic data, a large structural feature approximately
  19 square kilometersin size extending offshore. Government-owned
  gravity data supports our interpretations and refers to the feature as the Roberts
  Bank Gravity Anomaly. The Geological Survey of Canada has assigned the Georgia
  Basin a reserve estimate of 6.5 trillion cubic feet of natural gas. A commercial
  quantity of gas is yet to be discovered in the area. We plan to be inactive
  in the Fraser Valley in 2004.

Other Non-Core Properties 
                  
  Peavey/Morinville, Quirk Creek, Alexander, Simonette, Stanmore, and Westlock
  in Alberta and Elmore and Rapdan in Saskatchewan comprise 16,916 net acres (24,980
  gross) with a weighted average working interest of 68%. Of our total net acreage,
  53% is undeveloped.

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

As a Canadian issuer, we are required under Canadian law to comply with National
  Instrument 51-101Standards of Disclosure for Oil and Gas Activities(NI 51-101) issued by the Canadian Securities Administrators, in all of
  our reserves related disclosures. Canadian NI 51-101 was effective September
  30, 2003 and applies to financial years ended on or after December 31, 2003.
  Canadian NI 51-101 mandates significant changes in the way reporting issuers
  are required to determine and publicly disclose information relating to oil
  and gas reserves.

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

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

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

In the process of estimating our proved reserves on a constant-pricing basis,
  and their associated net present values, our actual December 31, 2003 weighted
  average commodity prices received and our associated operating costs incurred
  have been assumed to remain constant over the life of the reserves. The prices
  used for natural gas, natural gas liquids and crude oil were $6.18 per mcf,
  $25.38 per barrel and $39.69 per barrel, respectively.

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The reserve data set out in the summary table below is based on an independent
  engineering evaluation of our estimated proved oil and gas reserves effective
  January 1, 2004, as conducted by Sproule Associates Limited (Sproule).
  This evaluation was prepared in accordance with the definitions under NI 51-101.

|                        | Light and  |  |           |  |                 |  | Natural Gas |  |           | 
|----------------------- | ---------- |  | --------- |  | --------------- |  | ----------- |  | --------- | 
|                        | Medium Oil |  | Heavy Oil |  | Natural Gas (1) |  | Liquids     |  | Total (1) | 
|                        | (mbbl)     |  | (mbbl)    |  | (mmcf)          |  | (mbbl)      |  | (mboe)    | 
|Proved                  |            |  |           |  |                 |  |             |  |           | 
|Developed producing     | 214        |  | 4         |  | 14,963          |  | 792         |  | 3,504     | 
|Developed non-producing | 55         |  | -         |  | 1,832           |  | 4           |  | 364       | 
|Undeveloped             | 138        |  | -         |  | 2,758           |  | 17          |  | 615       | 
|Total proved            | 407        |  | 4         |  | 19,553          |  | 813         |  | 4,483     | 

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

Estimated Reserves Reconciliation

The following reconciliation shows the changes in our estimated reserves before
  royalties that occurred during Fiscal 2003. Opening reserves as at January 1,
  2003 were evaluated pursuant to the Canadian standards in effect at that time
  entitled, Guide for Engineers and Geologists Submitting Oil and Gas
  Reports to Canadian Provincial Securities Administrators (National
  Policy 2-B) while closing reserves as at January 1, 2004 were determined pursuant
  to the definitions of NI 51-101. Reserve definitions under these two standards
  differ and therefore are not directly comparable. For purposes of reconciliation,
  the line item referred to as revisions includes the variance between
  the two standards.

|                  | Light and  |   |           |  |                 |   | Natural Gas |   |           |  
|----------------- | ---------- | - | --------- |  | --------------- | - | ----------- | - | --------- | -
|                  | Medium Oil |   | Heavy Oil |  | Natural Gas (1) |   | Liquids     |   | Total (1) |  
|                  | (mbbl)     |   | (mbbl)    |  | (mmcf)          |   | (mbbl)      |   | (mboe)    |  
|December 31, 2003 | 997        |   | 2         |  | 24,781          |   | 1,170       |   | 6,299     |  
|Extensions        | 83         |   | -         |  | 432             |   | 3           |   | 158       |  
|Discoveries       | -          |   | -         |  | 499             |   | -           |   | 83        |  
|Revisions         | (491       | ) | 2         |  | (2,268          | ) | (162        | ) | (1,029    | )
|Production        | (182       | ) | -         |  | (3,891          | ) | (198        | ) | (1,028    | )
|December 31, 2003 | 407        |   | 4         |  | 19,553          |   | 813         |   | 4,483     |  

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

Net Present Values of Reserves

In the following two tables, we present Sproules estimated net present
  values effective January 1, 2004. It is not implicit that the undiscounted and
  discounted net present values presented represent the fair market values of
  our reserves, as the use of other assumptions could give rise to different results.

|($000s)                      |  | Before Income Taxes |  | After Income Taxes | 
|----------------------------- |  | ------------------- |  | ------------------ | 
|                              |  | Discount Rate       |  | Discount Rate      | 
|                              |  | 0%                  |  | 10%                | 
|Proved                        |  |                     |  |                    | 
|Developed
      producing     |  | 99,917              |  | 72,958             | 
|Developed
      non-producing |  | 4,684               |  | 2,756              | 
|Undeveloped                   |  | 16,445              |  | 12,229             | 
|Total proved                  |  | 121,046             |  | 87,943             | 

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In accordance with SEC regulations, the above disclosure of our reserve information
    is on an after-royalties basis. As our production is on a before-royalties
    basis consistent with other Canadian oil and gas companies, we also disclose
    our estimated proved reserves compliant with NI 51-101 on a before-royalties
    basis under constant price and operating cost assumptions as follows: Summary of Company Interest Estimated Reserves (Before Royalties)


|                        | Light and  |  |           |  |                 |  | Natural Gas |  |           | 
|----------------------- | ---------- |  | --------- |  | --------------- |  | ----------- |  | --------- | 
|                        | Medium Oil |  | Heavy Oil |  | Natural Gas (1) |  | Liquids     |  | Total (1) | 
|                        | (mbbl)     |  | (mbbl)    |  | (mmcf)          |  | (mbbl)      |  | (mboe)    | 
|Proved                  |            |  |           |  |                 |  |             |  |           | 
|Developed producing     | 261        |  | 5         |  | 18,175          |  | 962         |  | 4,257     | 
|Developed non-producing | 79         |  | -         |  | 2,640           |  | 5           |  | 524       | 
|Undeveloped             | 158        |  | -         |  | 3,678           |  | 20          |  | 791       | 
|Total proved            | 498        |  | 5         |  | 24,493          |  | 987         |  | 5,572     | 

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

|                  | Light and  |   |           |   |                 |   | Natural Gas |   |           |  
|----------------- | ---------- | - | --------- | - | --------------- | - | ----------- | - | --------- | -
|                  | Medium Oil |   | Heavy Oil |   | Natural Gas (1) |   | Liquids     |   | Total (1) |  
|                  | (mbbl)     |   | (mbbl)    |   | (mmcf)          |   | (mbbl)      |   | (mboe)    |  
|December 31, 2002 | 1,403      |   | 3         |   | 31,782          |   | 1,483       |   | 8,185     |  
|Extensions        | 102        |   | -         |   | 527             |   | 3           |   | 193       |  
|Discoveries       | -          |   | -         |   | 608             |   | -           |   | 101       |  
|Revisions         | (785       | ) | 3         |   | (3,661          | ) | (258        | ) | (1,649    | )
|Production        | (222       | ) | (1        | ) | (4,763          | ) | (241        | ) | (1,258    | )
|December 31, 2003 | 498        |   | 5         |   | 24,493          |   | 987         |   | 5,572     |  

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

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

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|---------------------------------------------------------- | 
|                                                           | 
|Item
      5. Operating and Financial Review and Prospects

The year covered by this annual report, Fiscal 2003, coincides with the calendar
  year and is the first full year since we changed our fiscal year end to December
  31 from March 31. Prior to this filing, our most recently filed annual report
  covered the nine-month period from April 1, 2002 to December 31, 2002. In this
  report, we may refer to the 12-month period ended December 31, 2003 as Fiscal
  2003, the nine-month period ended December 31, 2002 as Nine-Month
  Fiscal Transition 2002, the 12-month periods ended March 31, 2002 and
  2001 as Fiscal 2002 and Fiscal 2001, respectively, and
  the 12-month period ending December 31, 2004 as Fiscal 2004.

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

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

Certain statements in this Report, including those appearing under this
  Item 5, constitute forward-looking statements within the meaning
  of the United States Private Securities Litigation Reform Act of 1995, Section
  21E of the United States Securities Exchange Act of 1934, as amended, and Section
  27A of the United States Securities Act of 1933, as amended. Additionally, forward-looking
  statements may be made orally or in press releases, conferences, reports, on
  our 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 do not intend to update
  forward-looking statements to reflect actual results or changes in factors or
  assumptions affecting such forward-looking statements.

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|                        | 
|----------------------- | 
|                        | 
|Operating
      Results

Summary

During Fiscal 2003, we operated or participated in 14 drilled wells resulting
  in eight gas wells, four oil wells and two dry wells for an overall net working
  interest success rate of 80%. Of the 12 successful wells, six development wells
  were drilled at St. Albert, two exploration wells were drilled at Wimborne,
  one development well at Halkirk, Alberta and three exploration wells were drilled
  at Cypress/Chowade in British Columbia.

|Drilling
      Activity |             |  |                        |  |             |  |                |  |       |  |                | 
|----------------------- | ----------- |  | ---------------------- |  | ----------- |  | -------------- |  | ----- |  | -------------- | 
|                        |             |  |                        |  |             |  | Nine-Month     |  |       |  |                | 
|                        | Fiscal 2003 |  | Fiscal Transition 2002 |  | Fiscal 2002 | 
|                        | Gross       |  | Net
      W.I.         |  | Gross       |  | Net
      W.I. |  | Gross |  | Net
      W.I. | 
|Natural gas             | 8           |  | 5.3                    |  | 7           |  | 4.3            |  | 9     |  | 7.5            | 
|Crude oil               | 4           |  | 3                      |  | 2           |  | 1.5            |  | 1     |  | 0.7            | 
|Dry                     | 2           |  | 2                      |  | -           |  | -              |  | 4     |  | 2.8            | 
|Total                   | 14          |  | 10.3                   |  | 9           |  | 5.8            |  | 14    |  | 11.0           | 
|Success rate            |             |  | 80%                    |  |             |  | 100%           |  |       |  | 75%            | 

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

The following should be read in conjunction with our Financial Statements
  and the Notes to the Financial Statements included in this Report. The Financial
  Statements have been prepared in accordance with Canadian GAAP. The impact of
  significant differences between Canadian GAAP and U.S. GAAP is disclosed in
  Note 12 to our Financial Statements.

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, which is consistent with other Canadian oil and gas companies.

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

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

Due to certain accounting policy changes effected in Fiscal 2003, we have restated
  prior comparative information in order to conform to the presentation adopted
  (see Note 3 to our Financial Statements).

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|------------------ | 
|                   | 
|Executive Overview

Key Measures for the Comparative Periods Presented

|                                                  |                   |  | Nine- Month |  |                   |  
|------------------------------------------------- | ----------------- |  | ----------- |  | ----------------- | -
|                                                  |                   |  | Fiscal      |  |                   |  
|                                                  |                   |  | Transition  |  |                   |  
|($ 000s
      unless otherwise stated)           | Fiscal
      2003 |  | 2002        |  | Fiscal
      2002 |  
|Gross revenues                                    | 46,848            |  | 24,123      |  | 26,402            |  
|Cash flow from operations (1)                     | 23,097            |  | 10,810      |  | 11,337            |  
|Cash flow from operations per share ($/share )(1) | 1.08              |  | 0.53        |  | 0.56              |  
|Net earnings (loss)                               | 4,978             |  | 2,004       |  | (3,412            | )
|Net earnings (loss) per share ($/share)           | 0.23              |  | 0.10        |  | (0.17             | )
|                                                  |                   |  |             |  |                   |  
|Daily average production (boe/d)                  | 3,447             |  | 3,332       |  | 3,225             |  
|Total production (mboe)                           | 1,258             |  | 916         |  | 1,177             |  
|                                                  |                   |  |             |  |                   |  
|Capital expenditures                              | 31,747            |  | 12,578      |  | 22,111            |  
|Net debt (2)                                      | 19,313            |  | 16,818      |  | 13,281            |  
|Net debt to cash flow (times) (3)                 | 0.8:1             |  | 1.6:1       |  | 1.2:1             |  
|Net debt to
      cash flow annualized (times)(4) | 0.8:1             |  | 1.2:1       |  | 1.2:1             |  

Our gross revenueurs, cash flow from operations and total production were
  record highs during Fiscal 2003.

Comparisons of our results of Fiscal 2003 versus Nine-Month Fiscal Transition
  2002 were significantly affected by the three-month difference in period length.
  Two other significant factors contributed to the difference in many of our key
  measures between the two periods - gross revenues were greater in Fiscal 2003
  due to a 50% increase in our weighted average price for natural gas and our
  crude oil sales increased by 125%.

Daily average production of all commodities grew by 3% to 3,447 boe/d. Total
  production of all products was 1,258 mboe versus 916 mboe. This would have represented
  a 3% increase, had Nine-Month Fiscal Transition 2002 been annualized to 1,221
  mboe.

Our net earnings for Fiscal 2003 were the second highest in corporate history.
  The main reasons for this were the same key factors that generated higher gross
  revenues, cash flow from operations and total production outlined above. The
  impact of these factors on net earnings was lessened, however, by two main areas
  of expense - amortization and depletion, and exploration expenses which were
  higher by $5.7 million and $2.6 million, respectively. Amortization and depletion
  expense reflected: new capital expenditures related to production optimizations
  and leasehold acquisitions; the effects of transitioning to new reserve definitions
  (discussed below); and the repurchase of certain gross overriding royalty interests
  that previously burdened our total current and future corporate production by
  3%. Exploration expenses reflected higher costs for seismic data gathering and
  for the drilling of two unsuccessful wells, compared to no unsuccessful wells
  in Nine-Month Fiscal Transition 2002.

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

|                                              |                   |   | Nine-Month |   |                   | 
|--------------------------------------------- | ----------------- | - | ---------- | - | ----------------- | 
|                                              |                   |   | Fiscal     |   |                   | 
|($000s)                                      |                   |   | Transition |   |                   | 
|                                              | Fiscal
      2003 |   | 2002       |   | Fiscal
      2002 | 
|Cash provided by operating activities (GAAP)  | 28,294            |   | 11,457     |   | 9,779             | 
|Changes in non-cash working capital affecting |                   |   |            |   |                   | 
|operating (GAAP)                              | (5,197            | ) | (647       | ) | 1,558             | 
|Cash flow from
      operations (non-GAAP)    | 23,097            |   | 10,810     |   | 11,337            | 

|(2) | Net debt is working capital. We have no long-term debt.  
|--- | ---------------------------------------------------------
|(3) | Net debt divided by cash flow from operations.           
|(4) | Net debt divided by cash flow from operations annualized.

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Our primary strategy is to build through grassroots exploration and development.
  In particular, we remain committed to natural gas-based projects, as we believe
  it is a clean, secure and abundant energy source. Our secondary strategy is
  to target specific acquisitions that we believe will lead to higher returns
  and future prospects for exploration and development. Throughout 2003, we increased
  our total capital investment to $31.7 million and advanced our strategies in
  the following ways:

| | • | During Fiscal 2003, we spent $5.1 million on the acquisition
        of new lands. Our land holdings targeting natural gas increased by 11,177
        net acres (29,283 gross). This new acreage was located at Wimborne, Alberta
        and Cypress/Chowade, British Columbia;
      In addition, we repurchased three gross overriding royalty
        interests that previously burdened all our current and future corporate
        production from all producing and prospectively-producing properties by
        a total of 3%;                                                                                          
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| | • | We invested $15.2 million in the drilling of 14 gross
        exploratory and development wells (10.3 net), with an overall net working
        interest success rate of 80%. Of these wells, ten targeted natural gas
        and four targeted crude oil. Of the ten natural gas wells, two were unsuccessful.
        Four of the eight successful gas wells were drilled in British Columbia,
        three at Cypress/Chowade and one at Orion. The remaining four were drilled
        in Alberta, two at St. Albert, one at Halkirk and one at Wimborne. All
        four successful crude oil wells were at St. Albert; and
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
| | • | Our investment in facilities, pipelining and other
        assets grew by $1.8 million. Half of this capital was incurred at St.
        Albert to expand infrastructure that supports production optimization
        of existing reserves, while most of the balance was spent at Cypress/Chowade
        for new facilities construction.                                                                                                                                                                                                                                                                                       

In order to finance our record-high capital investment program described
  above, we took certain measures to expand our liquidity and capital resources.
  We issued 1.1 million common shares from treasury at a deemed price of $5.25
  per share, to pay for 85% of the repurchase of the gross overriding royalty
  interests referred to above and we increased our revolving, demand bank operating
  loan facility to $25.0 million from $21.0 million. These measures, accompanied
  by record cash flows and $1.5 million from option exercises improved our debt-to-cash-flow
  ratio from 1.2:1 to 0.8:1.

Our planned activity for Fiscal 2004 continues our primary strategy. We
  have budgeted to invest a record-high $37.1 million on capital expenditures
  and exploration expenses. The allocation of this budget reflects our changing
  focus  to invest proportionately more in northeast British Columbia. Seventy-one
  percent of our investment is budgeted for Cypress/Chowade and Orion, British
  Columbia. The majority of the remainder is earmarked for St. Albert and Wimborne,
  Alberta.

We expect a 13% growth in daily average production in Fiscal 2004, subject
  mostly to timing of regulatory approvals, third-party transportation and processing
  negotiations, and equipment availability. Based on our forecast of strong commodity
  prices, supported by our bank loan facility and our recently-announced private
  placement, we expect to meet our 2004 cash requirements.

38

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|                        | 
|----------------------- | 
|                        | 
|Financial
      Results

Cash Flow from Operations and Net Earnings

Fiscal 2003 vs Nine-Month Fiscal Transition 2002  Cash flow from operations was $23.1 million versus $10.8 million. Two variances
  accounted for the difference of $12.3 million between these two results:

| | • | A volume-based variance in revenue of $12.7 million
        that mainly reflects that the reporting periods differed in length by
        three months; and                          
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | A price-based variance in revenue of $10.0 million
        that reflects we realized higher weighted average prices in Fiscal 2003
        than in Nine-Month Fiscal Transition 2002.

| | • | Royalties expense  greater by $7.0 million;                      
| | - | ------------------------------------------------------------------
| | • | Production costs  greater by $1.5 million;                       
| | • | General and administrative expenses  greater by $1.6 million; and
| | • | Net interest expense  greater by $0.3 million.                   

Net earnings were $5.0 million versus $2.0 million. In accounting for the
  difference of $3.0 million between these two results, the same variances that
  affected our cash flows from operations referred to above were further affected
  by the following:

| | • | Amortization and depletion expense  greater by $5.7 million;                  
| | - | -------------------------------------------------------------------------------
| | • | Exploration expenses  greater by $2.6 million; and                            
| | • | Future income taxes and various other expenses  greater by $1.0
      million.

Nine-Month Fiscal Transition 2002 vs Fiscal 2002 Cash flow from operations was $10.8 million versus $11.3 million. In accounting
  for the difference of $0.5 million between these two results, higher weighted
  average prices realized in all commodities added $3.0 million. Due mainly to
  the differing lengths of the reporting periods, cash flow from operations was
  less by a net of $3.5 million ($5.3 million that related to the smaller volume
  of sales and $1.8 million that related to greater royalties expense).

Net earnings were $2.0 million versus a deficit of $3.4 million. In accounting
  for the difference of $5.4 million between these two results, the same variances
  that affected our cash flows from operations referred to above were further
  affected by less non-cash net expenses of $6.1 million as follows: $5.7 million
  that related to less amortization and depletion expense; $3.3 million that related
  to less exploration expense; and $2.9 million that related to greater future
  income tax expense.

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

39

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|        | 
|------- | 
|        | 
|Revenue

|                    |  | Fiscal
      2003 vs Nine-Month Fiscal |  | Nine-Month
      Fiscal Transition | 
|------------------- |  | -------------------------------------- |  | ---------------------------------- | 
|($000s)            |  | Transition 2002                        |  | 2002 vs Fiscal 2002                | 
|                    |  | Volume-                                |  | Price-                             | 
|                    |  | based                                  |  | based                              | 
|Natural gas         |  | 4,984                                  |  | 8,607                              | 
|Natural gas liquids |  | 1,332                                  |  | 1,302                              | 
|Crude oil           |  | 6,384                                  |  | 116                                | 
|Total               |  | 12,700                                 |  | 10,025                             | 

Fiscal 2003 vs Nine-Month Fiscal Transition 2002  Revenues were $46.8 million versus $24.1 million, a change of $22.7 million.
  While much of this change is a result of comparing a twelve-month period to
  a nine-month period, $12.7 million was due to volume-based variances and $10.0
  million was due to price-based variances.

Nine-Month Fiscal Transition 2002 vs Fiscal 2002  Revenues were $24.1 million versus $26.4 million, a downward net change
  of $2.3 million. While much of this change is a result of comparing a nine-month
  period to a twelve-month period, a decrease of $5.3 million was due to volume-based
  variances and an increase of $3.0 million was due to price-based variances.

Daily Average Production Rates and Total Production

|                                           |                   |  |     |   | Nine-
      Month |  |     |   |                   | 
|------------------------------------------ | ----------------- |  | --- | - | ----------------- |  | --- | - | ----------------- | 
|                                           |                   |  |     |   | Fiscal            |  |     |   |                   | 
|(Units as
      stated)                    |                   |  | %   |   | Transition        |  | %   |   |                   | 
|                                           | Fiscal
      2003 |  | Chg |   | 2002              |  | Chg |   | Fiscal
      2002 | 
|Daily average production rates             |                   |  |     |   |                   |  |     |   |                   | 
|Natural gas (mcf/d)                        |                   |  |     |   |                   |  |     |   |                   | 
|St. Albert                                 | 9,936             |  | (13 | ) | 11,360            |  | (6  | ) | 12,101            | 
|Halkirk                                    | 1,188             |  | (13 | ) | 1,368             |  | 67  |   | 822               | 
|Peavey/Morinville                          | 504               |  | (26 | ) | 678               |  | (60 | ) | 1,716             | 
|Other Alberta                              | 666               |  | (13 | ) | 768               |  | (55 | ) | 468               | 
|Cypress/Chowade,
      British Columbia    | 756               |  | -   |   | -                 |  | -   |   | -                 | 
|Total natural gas (mcf/d)                  | 13,050            |  | (8  | ) | 14,174            |  | (6  | ) | 15,107            | 
|Total natural
      gas (boe/d 6:1)        | 2,175             |  | (8  | ) | 2,363             |  | (6  | ) | 2,518             | 
|Natural gas liquids (bbl/d)                |                   |  |     |   |                   |  |     |   |                   | 
|St. Albert                                 | 656               |  | (5  | ) | 689               |  | 10  |   | 627               | 
|Other
      Alberta                        | 6                 |  | (33 | ) | 9                 |  | 125 |   | 4                 | 
|Total natural
      gas liquids (bbl/d)    | 662               |  | (5  | ) | 698               |  | 11  |   | 631               | 
|Crude oil (bbl/d)                          |                   |  |     |   |                   |  |     |   |                   | 
|St. Albert                                 | 609               |  | 126 |   | 270               |  | 275 |   | 72                | 
|Other,
      Saskatchewan                  | 1                 |  | -   |   | 1                 |  | (75 | ) | 4                 | 
|Total crude
      oil (bbl/d)              | 610               |  | 125 |   | 271               |  | 257 |   | 76                | 
|Total daily average production (boe/d)     | 3,447             |  | 3   |   | 3,332             |  | 3   |   | 3,225             | 
|Total production
      all products (mboe) | 1,258             |  | n/m |   | 916               |  | n/m |   | 1,177             | 

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

Our total daily average production of all commodities increased by 115 boe/d
  or 3%, to 3,447 boe/d. Of this increase, natural gas and natural gas liquids
  decreased in aggregate by 224 boe/d or 7%, while crude oil increased by 339
  boe/d or 125%. The aggregate decrease in natural gas and natural gas liquids
  was mostly the net result of a decrease due

40

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| | 
| | 
| | 
|



Nine-Month Fiscal Transition 2002 vs Fiscal 2002 Total daily average production of all products increased by a net 107 boe/d
  or 3%, to 3,332 boe/d. Of this net increase, natural gas and natural gas liquids
  decreased in aggregate by 88 boe/d or 3%, while crude oil increased by 195 boe/d
  or 257%. For the most part, the decrease in natural gas and natural gas liquids
  was due to naturally declining reservoir pressures at St. Albert. The increase
  in crude oil was due to the start-up of flush production from a new oil well
  at St. Albert.

Weighted Average Commodity Prices

|                            |                   |  |     |  | Nine-      |  |     |  |                   | 
|--------------------------- | ----------------- |  | --- |  | ---------- |  | --- |  | ----------------- | 
|                            |                   |  |     |  | Month      |  |     |  |                   | 
|                            |                   |  |     |  | Fiscal     |  |     |  |                   | 
|                            |                   |  | %   |  | Transition |  | %   |  |                   | 
|(Units as
      stated)     | Fiscal
      2003 |  | Chg |  | 2002       |  | Chg |  | Fiscal
      2002 | 
|Natural gas ($/mcf)         | 6.56              |  | 50  |  | 4.36       |  | 14  |  | 3.81              | 
|Natural gas liquids ($/bbl) | 27.68             |  | 32  |  | 20.90      |  | 8   |  | 19.30             | 
|Crude oil ($/bbl)           | 42.98             |  | 4   |  | 41.40      |  | 21  |  | 34.33             | 

Fiscal 2003 vs Nine-Month Fiscal Transition 2002  Our weighted average prices of natural gas, natural gas liquids and crude
  oil increased by 50%, 32% and 4%, respectively.

At the beginning of Fiscal 2003, stronger industry-wide prices for natural
  gas reflected an extended period of winter cold and lower inventory supplies
  in North America. Late in the year, natural gas prices again strengthened due
  to fears of cold weather in the east. During most of Fiscal 2003, industry-wide
  prices for crude oil were stronger, due in large measure to continuing geo-political
  uncertainties and tighter North American supplies. Additionally, demand for
  crude oil in Asia grew and the relative value of the U.S. dollar declined.

Our natural gas liquids were 45% natural gas-based and 55% crude oil-based,
  therefore, our weighted average price for liquids followed the respective trends
  mentioned above.

Nine-Month Fiscal Transition 2002 vs Fiscal 2002 Weighted average prices realized from the sale of all our commodities increased
  by percentages ranging from 8% to 21%.

Hedging

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

41

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| | 
| | 
| | 
|

Royalties, Mineral Taxes and Royalty Credits

|                                                 |                   |   |     |  | Nine-      |   |     |  |                   |  
|------------------------------------------------ | ----------------- | - | --- |  | ---------- | - | --- |  | ----------------- | -
|                                                 |                   |   |     |  | Month      |   |     |  |                   |  
|                                                 |                   |   |     |  | Fiscal     |   |     |  |                   |  
|                                                 |                   |   | %   |  | Transition |   | %   |  |                   |  
|($ 000s
      unless otherwise stated)          | Fiscal
      2003 |   | Chg |  | 2002       |   | Chg |  | Fiscal
      2002 |  
|Crown                                            | 4,698             |   | n/m |  | 1,252      |   | n/m |  | 1,317             |  
|Freehold and overriding                          | 6,818             |   | n/m |  | 3,327      |   | n/m |  | 4,067             |  
|Freehold mineral taxes                           | 1,346             |   | n/m |  | 943        |   | n/m |  | 1,116             |  
|Royalty tax credit (Alberta)                     | (401              | ) | n/m |  | (178       | ) | n/m |  | (159              | )
|Royalty drilling
      credit (British Columbia) | (122              | ) | -   |  | -          |   | -   |  | -                 |  
|Total royalties                                  | 12,339            |   | n/m |  | 5,344      |   | n/m |  | 6,341             |  
|Unit total royalties
      per boe ($)           | 9.81              |   | 68  |  | 5.83       |   | 8   |  | 5.39              |  

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

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

Nine-Month Fiscal Transition 2002 vs Fiscal 2002  Total royalties were $5.3 million versus $6.3 million. This would have
  represented an increase of 13%, had Nine-Month Fiscal Transition 2002 been annualized
  to $7.1 million.

Unit royalties expense increased by $0.44 or 8% to $5.83 per boe primarily
  due to royalty obligations associated with production of prior periods and higher
  commodity prices.

Production Costs

|                                        |                   |  |     |   | Nine-      |  |     |  |                   | 
|--------------------------------------- | ----------------- |  | --- | - | ---------- |  | --- |  | ----------------- | 
|                                        |                   |  |     |   | Month      |  |     |  |                   | 
|                                        |                   |  |     |   | Fiscal     |  |     |  |                   | 
|                                        |                   |  | %   |   | Transition |  | %   |  |                   | 
|($ 000s
      unless otherwise stated) | Fiscal
      2003 |  | Chg |   | 2002       |  | Chg |  | Fiscal
      2002 | 
|Production costs                        | 7,011             |  | n/m |   | 5,470      |  | n/m |  | 5,846             | 
|Unit production
      costs per ($)     | 5.57              |  | (7  | ) | 5.97       |  | 20  |  | 4.97              | 

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

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

Nine-Month Fiscal Transition 2002 vs Fiscal 2002  Total production costs were $5.5 million versus $5.8 million. This would
  have represented an increase of 26%, had Nine-Month Fiscal Transition 2002 been
  annualized to $7.3 million.

42

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| | 
| | 
| | 
|




Amortization and Depletion Expense (A&D)

|                                         |                   |  |     |  | Nine-      |   |     |   |                   |  
|---------------------------------------- | ----------------- |  | --- |  | ---------- | - | --- | - | ----------------- | -
|                                         |                   |  |     |  | Month      |   |     |   |                   |  
|                                         |                   |  |     |  | Fiscal     |   |     |   |                   |  
|                                         |                   |  | %   |  | Transition |   | %   |   |                   |  
|($ 000s
      unless otherwise stated)  | Fiscal
      2003 |  | Chg |  | 2002       |   | Chg |   | Fiscal
      2002 |  
|A&D before the following:                | 11,606            |  | n/m |  | 5,924      |   | n/m |   | 5,336             |  
|Ceiling test adjustment                  | 316               |  | 29  |  | 445        |   | (93 | ) | 6,783             |  
|Depletion of asset
      retirement cost | 99                |  | 57  |  | 63         |   | (7  | ) | 68                |  
|Amortization
      of deferred items     | -                 |  | -   |  | (109       | ) | 53  |   | (230              | )
|Total A&D expense                        | 12,021            |  | n/m |  | 6,323      |   | n/m |   | 11,957            |  
|Unit A&D
      expense per boe ($)       | 9.55              |  | 38  |  | 6.90       |   | (32 | ) | 10.16             |  

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

Unit A&D expense increased by a net of $2.65 or 38%, to $9.55 per boe
  due mainly to the following:

| | • | An increase of $1.23 per boe due to higher capital-to-reserve
        ratios. Most of this increase is for recent crude oil discoveries and
        natural gas optimizations at St. Albert;                                                                                                                               
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | • | An increase of $0.98 per boe due to additional depletion
        related to the July 7, 2003 repurchase of gross overriding royalty interests
        that previously burdened our total current and future corporate production
        by 3% (see Note 7[d] to our Financial Statements for further details);
        and
| | • | An increase of $0.55 per boe due to significant growth
        in our leasehold base.                                                                                                                                                                                                                                      

Nine-Month Fiscal Transition 2002 vs Fiscal 2002  Our total A&D expense was $6.3 million versus $12.0 million. This would
  have represented a decrease of 30%, had Nine-Month Fiscal Transition 2002 been
  annualized to $8.4 million.

Unit A&D expense decreased by a net of $3.26 or 32%, to $6.90 per boe
  due primarily to a Peavey/Morinville ceiling test adjustment recorded in Fiscal
  2002.

Exploration Expenses

|                                            |                   |  |     |  | Nine-      |  |     |   |                   | 
|------------------------------------------- | ----------------- |  | --- |  | ---------- |  | --- | - | ----------------- | 
|                                            |                   |  |     |  | Month      |  |     |   |                   | 
|                                            |                   |  |     |  | Fiscal     |  |     |   |                   | 
|                                            |                   |  | %   |  | Transition |  | %   |   |                   | 
|($ 000s
      unless otherwise stated)     | Fiscal
      2003 |  | Chg |  | 2002       |  | Chg |   | Fiscal
      2002 | 
|Drilling (1)                                | 1,278             |  | n/m |  | 325        |  | n/m |   | 3,821             | 
|Seismic data activity                       | 2,349             |  | n/m |  | 934        |  | n/m |   | 649               | 
|Other                                       | 439               |  | n/m |  | 187        |  | n/m |   | 176               | 
|Total exploration expenses                  | 4,066             |  | n/m |  | 1,446      |  | n/m |   | 4,646             | 
|Unit exploration
      expenses per boe ($) | 3.23              |  | 104 |  | 1.58       |  | (60 | ) | 3.95              | 

|(1) | We follow the successful efforts method of accounting,
        whereby costs of drilling an unsuccessful well are expensed when it becomes
        known the well did not result in a discovery of proved reserves.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

43

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| | 
| | 
| | 
|




Nine-Month Fiscal Transition 2002 vs Fiscal 2002  Total exploration expenses were $1.4 million versus $4.6 million. This
  would have represented a decrease of 59%, had Nine-Month Fiscal Transition 2002
  been annualized to $1.9 million.

Unit exploration expenses decreased by $2.37 or 60%, to $1.58 per boe. The
  main reason for this decrease was that all drilling attempts were successful
  in Nine-Month Fiscal Transition 2002 compared to a total of ten unsuccessful
  wells in Fiscal 2002, six at Peavey/Morinville, one each at Quirk Creek, Alexander
  and Orion, and one reentry/workover at St. Albert.

Interest Expense - Net

|                                        |                   |  |     |  | Nine-      |  |     |  |                   | 
|--------------------------------------- | ----------------- |  | --- |  | ---------- |  | --- |  | ----------------- | 
|                                        |                   |  |     |  | Month      |  |     |  |                   | 
|                                        |                   |  |     |  | Fiscal     |  |     |  |                   | 
|                                        |                   |  | %   |  | Transition |  | %   |  |                   | 
|($ 000s
      unless otherwise stated) | Fiscal
      2003 |  | Chg |  | 2002       |  | Chg |  | Fiscal
      2002 | 
|Net interest expense                    | 713               |  | n/m |  | 453        |  | n/m |  | 472               | 
|Unit interest
      expense per boe ($) | 0.57              |  | 16  |  | 0.49       |  | 23  |  | 0.40              | 

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

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

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

General and Administrative Expenses (G&A)

|                                        |                   |  |     |  | Nine-      |  |     |   |                   | 
|--------------------------------------- | ----------------- |  | --- |  | ---------- |  | --- | - | ----------------- | 
|                                        |                   |  |     |  | Month      |  |     |   |                   | 
|                                        |                   |  |     |  | Fiscal     |  |     |   |                   | 
|                                        |                   |  | %   |  | Transition |  | %   |   |                   | 
|($ 000s
      unless otherwise stated) | Fiscal
      2003 |  | Chg |  | 2002       |  | Chg |   | Fiscal
      2002 | 
|G&A expenses                            | 3,415             |  | n/m |  | 1,839      |  | n/m |   | 2,347             | 
|Unit G&A
      expenses per boe ($)     | 2.71              |  | 35  |  | 2.01       |  | (4  | ) | 1.99              | 

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

Unit G&A expenses increased by a net $0.70 or 35%, to $2.71 per boe.
  Of this increase, 40% was due to the first-time recognition of stock-based compensation
  made available to directors and employees under our corporate stock option plan
  (see Note 3 to our Financial Statements for further details). Other increases
  were mainly attributed to: new staff hires and certain salary adjustments; computer
  technical and software support; gas marketing advice; and other essential professional
  services.

44

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|                                                 | 
|------------------------------------------------ | 
|                                                 | 
|Nine-Month Fiscal Transition 2002 vs Fiscal 2002




Income Tax Expense

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

|                                |                   |  |     |  | Nine-      |  |     |  |                   |  
|------------------------------- | ----------------- |  | --- |  | ---------- |  | --- |  | ----------------- | -
|                                |                   |  |     |  | Month      |  |     |  |                   |  
|                                |                   |  |     |  | Fiscal     |  |     |  |                   |  
|                                |                   |  | %   |  | Transition |  | %   |  |                   |  
|($ 000s)                       | Fiscal
      2003 |  | Chg |  | 2002       |  | Chg |  | Fiscal
      2002 |  
|Current income tax expense      | 632               |  | n/m |  | 207        |  | n/m |  | 58                |  
|Future income
      tax expense | 1,579             |  | n/m |  | 975        |  | n/m |  | (1,904            | )
|Total income
      tax expense  | 2,211             |  | n/m |  | 1,182      |  | n/m |  | (1,846            | )

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

Nine-Month Fiscal Transition 2002 vs Fiscal 2002  Total income tax expense increased to $1.2 million from a recovery of $1.8
  million. This increase was consistent with our pre-tax earnings. Our effective
  tax rate was 37.1%, which was in line with statutory tax rates.

|                                            |                   |  | Nine-      |  |                   |  |           | 
|------------------------------------------- | ----------------- |  | ---------- |  | ----------------- |  | --------- | 
|                                            |                   |  | Month      |  |                   |  |           | 
|                                            |                   |  | Fiscal     |  |                   |  | Maximum   | 
|                                            |                   |  | Transition |  |                   |  | Annual    | 
|($ 000s)                                   | Fiscal
      2003 |  | 2002       |  | Fiscal
      2002 |  | Deduction | 
|Canadian exploration expense                | -                 |  | 1,586      |  | -                 |  | 100%      | 
|Canadian development expense                | 8,893             |  | 5,246      |  | 3,772             |  | 30%       | 
|Undepreciated capital costs                 | 10,934            |  | 10,356     |  | 10,297            |  | 20% -100% | 
|Canadian oil
      and gas property expense | 21,168            |  | 17,417     |  | 16,471            |  | 10%       | 
|Total income
      tax pools                | 40,995            |  | 34,605     |  | 30,540            |  |           | 

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

Critical Accounting Policies

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

45

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|                   | 
|------------------ | 
|                   | 
|Reserves Estimates

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

Natural Gas and Oil Interests

We follow the successful efforts method of accounting for our natural gas
  and oil activities, as described in Note 2 to our Financial Statements. The
  application of this method requires us to make significant judgments and decisions
  based on available geological, geophysical, engineering and economic data. The
  results from drilling can take considerable time to analyze and when it is determined
  that drilling has been unsuccessful in establishing commercial reserves, the
  costs of drilling are written off 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 are either
  partially or fully below the book value of a property 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 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.

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

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

During Fiscal 2002, ceiling test adjustments totaled $6.8 million, 99% of
  which related to the Peavey/Morinville property.

Accounting Policy Changes

Canadian Pronouncements  Effective March 31, 2004, all reporting issuers in Canada are subject to
  new disclosure requirements as per National Instrument 51-102 Continuous
  Disclosure Obligations. This new instrument proposes shorter reporting
  periods for filing of annual and interim Financial Statements, managements
  discussion and analysis and Canadian Annual Information Form (AIF). The instrument
  also requires enhanced disclosure in the annual and interim Financial Statements,
  managements discussion and analysis and AIF. Under this new instrument,
  it will no longer be mandatory for us to mail annual and interim Financial Statements
  and managements discussion and analysis to shareholders, but rather these
  documents will be provided on an as requested basis. We continue
  to assess the implications of this new instrument.

Effective December 31, 2003, we early-adopted the amended standard CICA
  3870, Stock-Based Compensation and Other Stock-Based Payments.The amended
  standard has an expanded requirement to apply the fair-value based method of
  accounting for all stock-based payments, direct awards of stock and awards that
  call for settlement in cash, including those granted to directors, employees
  and non-employees. Prior to its amendment, CICA 3870 was first adopted by us
  on April 1, 2002. During the period April 1, 2002 to December 31, 2002, we used
  the fair-value based method to account only for stock options granted to non-employees.
  (See Note 3 to our Financial Statements for further details).

46

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| | 
| | 
|

Asset Retirement Obligations


Other accounting standards issued by the CICA during the year ended December
  31, 2003 are not expected to materially impact us.

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

Interpretation No. 46, Consolidation of Variable Interest Entities,
  effective December 31, 2004.

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

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

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

We continue to assess the applicability of these standards.

Inflation

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

Impact of Foreign Currency Fluctuations

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

Government Policies

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

Liquidity and Capital Resources

Sources and Uses of Cash

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

47

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| | 
|

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


|                                             |   |         |   |   | Nine-Month |   |   |                   |   |   |                   |   |   |        |  
|-------------------------------------------- | - | ------- | - | - | ---------- | - | - | ----------------- | - | - | ----------------- | - | - | ------ | -
|                                             |   |         |   |   | Fiscal     |   |   |                   |   |   |                   |   |   |        |  
|                                             |   | Fiscal  |   |   | Transition |   |   |                   |   |   |                   |   |   | Fiscal |  
|($ 000s
      unless otherwise stated)      |   | 2003    |   |   | 2002       |   |   | Fiscal
      2002 |   |   | Fiscal
      2001 |   |   | 2000   |  
|Weighted average commodity price volatility: |   |         |   |   |            |   |   |                   |   |   |                   |   |   |        |  
|Natural gas                                  | $ | 6.56    |   | $ | 4.36       |   | $ | 3.81              |   | $ | 6.22              |   | $ | 2.72   |  
|Crude
      oil                              | $ | 42.98   |   | $ | 41.40      |   | $ | 34.33             |   | $ | 43.60             |   | $ | 16.74  |  
|                                             |   |         |   |   |            |   |   |                   |   |   |                   |   |   |        |  
|Timing differences between:                  |   |         |   |   |            |   |   |                   |   |   |                   |   |   |        |  
|Cash flow from operations (1);
      and     |   | 23,097  |   |   | 10,810     |   |   | 11,337            |   |   | 18,168            |   |   | 5,634  |  
|Capital expenditures, exploration            |   |         |   |   |            |   |   |                   |   |   |                   |   |   |        |  
|expenses
      and proceeds on sale          |   |         |   |   |            |   |   |                   |   |   |                   |   |   |        |  
|of
      natural gas and oil interests       |   | (27,102 | ) |   | (14,022    | ) |   | (26,753           | ) |   | (12,432           | ) |   | (7,026 | )
|Total timing
      differences               |   | (4,005  | ) |   | (3,212     | ) |   | (15,416           | ) |   | 5,736             |   |   | (1,392 | )
|                                             |   |         |   |   |            |   |   |                   |   |   |                   |   |   |        |  
|Cash used in investing activities:           |   |         |   |   |            |   |   |                   |   |   |                   |   |   |        |  
|Bank operating indebtedness                  |   | 2,041   |   |   | (2,997     | ) |   | 15,593            |   |   | (6,000            | ) |   | 3,750  |  
|Issuance of common shares                    |   | 1,511   |   |   | -          |   |   | 455               |   |   | 200               |   |   | 117    |  
|Repurchases
      of common shares           |   | -       |   |   | (326       | ) |   | (290              | ) |   | (90               | ) |   | (1,377 | )
|                                             |   | 3,552   |   |   | (3,323     | ) |   | 15,758            |   |   | (5,890            | ) |   | 2,490  |  
|Changes in non-cash
      working capital    |   | (453    | ) |   | (6,535     | ) |   | 342               |   |   | (154              | ) |   | 1,098  |  

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

Financing activitiesIn 1999, we first established
  a revolving, demand bank operating loan facility with our corporate bank. On
  May 16, 2003, our loan was increased to $25.0 million from $21.0 million. Principal
  balances outstanding are charged interest at prime plus three-eighths of a percent
  (at December 31, 2003, the banks prime rate was 4.5%) 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 one-eighth of a percent per
  annum is levied on the unused portion of the facility.

The facility is subject to a semi-annual review. The next review will be
  undertaken on May 27, 2004. This review will include assessments of our January
  1, 2004 reserves and daily production estimates and a full evaluation of our
  financial position and operations. As at December 31, 2003, the undrawn balance
  of our loan facility was $10.4 million, after allowing for bank indebtedness
  of $1.4 million. Repayment is in full, monthly. Our loan agreement contains
  covenants that require prior approval of our bank (e.g. mergers, capital distributions,
  other pledges of security and asset disposals). At December 31, 2003, we were
  compliant with all covenants.

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

During Fiscal 2003, we repurchased certain gross overriding royalty interests
  that previously burdened our total current and future production by 3%. The
  transaction was financed through the payment of $1.0 million in cash and the
  issuance of 1.05 million common shares at a deemed price of $5.25 per share.

Over the past five fiscal periods, our aggregate cash inflows arising from
  the issuance of common shares have amounted to $2.3 million. During the same
  period, cash outflows from the repurchase of common shares were $2.1 million,
  bringing the effect of all stock transactions to a net cash inflow of $0.2 million.

48

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On April 30, 2004, we entered into a bought-deal private placement with
  both Octagon Capital Corporation as lead underwriter and Raymond James Ltd.
  Pursuant to the terms of the agreement, we have agreed to issue, by way of private
  placement, 2,000,000 flow-through common shares at $5.60 each on a firm underwriting
  basis. As well, at the option of the underwriters, exercised at least one business
  day before closing, we have agreed to issue 400,000 common shares at $4.55 each.
  If the underwriters exercise their option, the total gross proceeds of the offering
  will be $13,020,000.

The net proceeds of the share offering will be used to accelerate our continued
  exploration and development of our core natural gas properties at Cypress/Chowade
  and Orion in northeast British Columbia. Proceeds from the flow-through shares
  will be used to incur qualifying Canadian Exploration Expense (CEE)
  as defined in the Income Tax Act (Canada) and we will renounce, for the 2004
  taxation year, such CEE in favour of the original holders of the flow-through
  shares in an amount equal to the issue price for each flow-through share. Closing
  is subject to normal closing conditions including obtaining required regulatory
  approvals and is scheduled to occur on or about May 19, 2004.

We expect to source the financing costs related to the bought-deal financing
  agreement above from the undrawn portion of our line of credit. To the extent
  that underwriters exercise their option to acquire non-flow-through shares,
  proceeds from the sale of those shares of our Common Stock would be added to
  the undrawn line of credit balance.

Working capital Changes in our working capital
  and net debt levels are primarily dependent upon our cash flow from operations,
  the amount of our capital expenditures and exploration expenses, and the timing
  of incurred field activities.

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

Our year end debt level, comprised of working capital and the outstanding
  balance of our operating bank loan, reflects a debt-to-cash-flow ratio of 0.8:1
  (Nine-Month Fiscal Transition 2002  1.2:1 annualized; Fiscal 2002 
  1.2:1, Fiscals 2001 and 2000  nil).

Cash Requirements

Our future liquidity is dependent upon cash flows generated from our operational
  activities, our capital investment programs and the flexibility of capital sources.
  Changes in the weighted average prices we obtain for the sales of our commodities
  will impact our cash flow from operations and the extent to which we may draw
  from, or have made available to us, bank operating credit for 2004 (see Item
  11 - Weighted Average Prices and the Effect of Adversity).

Cash Management

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

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

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|                        | 
|----------------------- | 
|                        | 
|Outlook for Fiscal 2004

Our primary strategy is to grow organically through the drill bit by pursuing
  a forward-looking exploration strategy. We believe that northeast British Columbia
  offers some of the best opportunities in the western Canadian sedimentary basin
  for long-term sustainable growth. Of our current total net undeveloped land
  holdings, 76% are located in British Columbia.

Our capital expenditure and exploration expense budget for Fiscal 2004 is
  $37.1 million, of which we plan to invest $26.1 million or 71% in northeast
  British Columbia. (For full details, see Item 4  Fiscal 2004 
  Budgeted Capital Expenditures and Exploration Expenses).

British Columbia has become an attractive province for oil and gas investment
  by implementing several new initiatives: enhancing existing energy policies;
  streamlining regulations; increasing investments in infrastructure; and implementing
  new royalty incentives.

Our Fiscal 2004 target daily average and exit production rates are 3,900
  and 4,400 boe per day, respectively. Our target production rates do not include
  potential increases resulting from work being conducted during the year on certain
  undeveloped properties. A discussion of these properties and their potential
  impact on 2004 production follows the table below (see Item 5 - Undeveloped
  Properties (Those Not Considered in 2004 Target Production Rates)):

|                                                | Target
      Daily     | 
|----------------------------------------------- | ---------------------- | 
|(Units as
      stated)                         | Production
      Rates | 
|Natural gas (mcf/d)                             |                        | 
|St. Albert                                      | 9,320                  | 
|Halkirk                                         | 965                    | 
|Peavey/Morinville                               | 785                    | 
|Other Alberta (four properties)                 | 790                    | 
|Cypress/Chowade,
      British Columbia         | 4,850                  | 
|Total natural gas (mcf/d)                       | 16,710                 | 
|Total natural
      gas (boe/d 6:1)             | 2,785                  | 
|Natural gas liquids (bbl/d)                     |                        | 
|St. Albert                                      | 600                    | 
|Other
      Alberta (four properties)           | 10                     | 
|Total natural
      gas liquids (bbl/d)         | 610                    | 
|Crude oil                                       |                        | 
|St.
      Albert                                | 505                    | 
|Total crude
      oil (bbl/d)                   | 505                    | 
|Target daily average production rate (boe/d)    | 3,900                  | 
|Target daily
      exit production rate (boe/d) | 4,400                  | 

Developed Properties(Those Considered in 2004 Target Production
  Rates) 
                  
  Alberta St. Albert- As stated above, work will continue to optimize production
  throughout the year. Crude oil zones of continuing interest to us are the Wabamum
  D-1 formation, Nisku D-2 formation, and Leduc D-3 formation, while natural gas
  zones of interest are the Ostracod zone and Belly River formation. The timing
  of our activities is subject to seasonal road-use restrictions and regulatory
  approvals.

British Columbia  Cypress/Chowade Included in our budget is our 50%
  share of a 32 kilometer, 8 sales pipeline to the Sikanni, British Columbia
  and a 30 mmcf/d sour gas plant. The initial leg of the pipeline was scheduled
  for construction in the first quarter of 2004. The second leg of the pipeline
  and the gas plant are scheduled for construction in the fourth quarter of 2004.
  The impact of these facilities is expected to have a marginal impact on our
  2004 target production rates due to the estimated timing of their start-up.
  Timing is subject to regulatory approvals, negotiation of third-party processing
  agreements and the availability of equipment.

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|---------------------------------------------------------------------------------- | 
|                                                                                   | 
|Undeveloped Properties(Those Not Considered in 2004
      Target Production Rates)

Alberta  Wimborne


We are prospecting for Cretaceous Age sandstone reservoirs in a complex,
  fluvial environment using an extensive 3D seismic database. Each well is targeting
  a separate and distinct seismic anomaly. One of these seismic anomalies is analogous
  to a multi-well producing gas pool approximately ten kilometers away.

The area is accessible year round and is in close proximity to third-party
  transportation and processing facilities. If successful, we expect tie-in to
  occur late in 2004, subject to regulatory approvals and negotiation of third-party
  agreements.

British Columbia  Cypress/Chowade  We have budgeted three, exploration
  multi-zone outpost gas wells, scheduled for drilling in the second and third
  quarters of 2004. Based on nearby wells, our estimated resource potential of
  each of our wells ranges between three and five bcf per zone, and approximate
  production rates range between one  five mmcf/d per zone. Each well is
  budgeted at a 30% working interest.

During 2003, we participated in nine wells resulting in eight gas wells
  and one unsuccessful well, for an overall drilling success rate of 89%. Our
  2004 wells are targeting multi-zone, natural gas-bearing Triassic Age sandstone
  and carbonate reservoirs. Our locations have been selected by correlating 2D
  seismic data and drilling results.

Orion We have budgeted two 100% exploration gas wells, scheduled
  for drilling in the third quarter of 2004. One is drilling for a Slave Point
  formation target and the other a Bluesky formation target.

Based on information available to us on an offset Slave Point formation
  producing well, we estimate our Slave Point formation well could encounter an
  estimated pool size of 25 bcf and produce between five  ten mmcf/d. Similar
  information on several producing offset Bluesky formation wells suggests we
  could reasonably expect our Bluesky formation well to encounter an estimated
  pool size of 12 bcf and produce between one  three mmcf/d per well.

The proposed Slave Point formation well is approximately two kilometers
  away from a producing Slave Point formation gas well in the adjacent spacing
  unit. The proposed Bluesky formation well is offset by a multi-well, producing
  Bluesky formation gas pool approximately the same distance away. Both wells
  are targeting seismic features identified on our lands using 3D seismic data.

The nearest tie-in point for the wells is two kilometers away. If one or
  both wells are successful, tie-ins are expected to occur in late 2004 or early
  2005. Tie-ins are subject to regulatory approvals, winter access-only conditions,
  availability of equipment, and negotiation of third-party transportation and
  processing.

Sensitivity Analysis

The following table shows the effect on cash flow of certain changes in
  volume, price and interest rates. Numbers presented reflect the sensitivity
  impact on our estimated Fiscal 2004 activity.

|                    |                                |  | ————Changes
      in———— |  | Effect
      on Cash Flow
|------------------- | ------------------------------ |  | ------------------------ |  | -------------------------
|Sensitivities       |                                |  | Volume                   |  | Price                    
|Production          |  natural gas (mmcf/d)         |  | 1                        |  | -                        
|                    |  natural gas liquids (bbl/d)) |  | 100                      |  | -                        
|                    |  crude oil (bbl/d)            |  | 100                      |  | -                        
|Price               |  natural gas ($/mcf)          |  | -                        |  | 0.50                     
|                    |  natural gas liquids ($/bbl)  |  | -                        |  | 1.00                     
|                    |  crude oil ($/bbl)            |  | -                        |  | 1.00                     
|Interest
      rate | (%)                            |  | -                        |  | -                        

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|                                        | 
|--------------------------------------- | 
|Contractual Obligations and Commitments | 

We have an operating lease in respect of our office premises, as discussed in Note 13 to our Financial Statements. Additionally, we have asset retirement obligations relating to the clean up and restoration of wellsites
and associated production facilities.

|Commitments  Cash and Non-Cash
      Type Obligations                                                                 
|-----------------------------------------------------------------------------------------------------------------------
|Payments or Work Commitments Due                                                                                       
|By Period                                                                                                              
|                                                                                                                       
|($000s)                                                                                                               
|Cash type: operating lease obligations (office space)                                                                  
|Non-cash type: asset retirement obligations(1)                                                                         
|Total                                                                                                                  
|(1)Asset retirement obligations represent estimates
      of clean-up and restoration commitments and are undiscounted.

As at December 31, 2003, we
  recognized $1.6 million on our balance sheet for future asset retirement obligations.
  We engage independent engineering consultants to assist in assessing our total
  future asset retirement liabilities. While we cannot predict their ultimate
  cost, we currently estimate the total cost to clean up all our operating facilities
  to be $3.3 million.

Off-Balance Sheet Arrangments

As at December 31, 2003, we had no off-balance
  sheet arrangements.

Item 6. Directors, Senior Management and Employees

Directors and Senior Management

The following is information regarding our Directors,
  Senior Management and Employees as of December 31, 2003.

|Name                              | Position Held                  | Age | Residence      
|--------------------------------- | ------------------------------ | --- | ---------------
|Directors and Executive Officers: |                                |     |                
|Wayne J. Babcock                  | President & CEO, Director      | 60  | Vancouver, B.C.
|Donald K. Umbach                  | Vice President & COO, Director | 50  | Vancouver, B.C.
|John A. Greig                     | Director                       | 62  | Vancouver, B.C.
|Jonathan A. Rubenstein            | Director                       | 54  | Vancouver, B.C.
|David J. Jennings                 | Director                       | 40  | Vancouver, B.C.
|John Lagadin                      | Director                       | 66  | Calgary, Alta. 
|William B. Thompson               | Director                       | 59  | Kelowna, B.C.  
|Michael A. Bardell                | CFO & Corporate Secretary      | 57  | Vancouver, B.C.
|David G. Grohs                    | Vice President, Production     | 38  | Vancouver, B.C.

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| | 
| | 

|Wayne J. Babcock 
      President, Chief
      Executive Officer,
      Director | 
|-------------------------------------------------------------------------------- | 

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

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

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

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

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

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

|John A. GreigDirector | 
|--------------------- | 

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 Blackstone Ventures Inc. Eurozinc Mining Corp.,
  and Diamondex Resources Ltd.

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|Jonathan A. RubensteinDirector | 
|------------------------------ | 

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

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

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

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

|David J. JenningsDirector | 
|------------------------- | 

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

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

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

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|John LagadinDirector | 
|-------------------- | 

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

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

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

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|Michael A. BardellChief Financial
      Officer, Corporate
      Secretary | 
|-------------------------------------------------------------------------- | 

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

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

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

|David G. GrohsVice-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 15 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.

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

Compensation

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

The following table sets forth all annual and long-term compensation
  for services in all capacities to us for Fiscal 2003 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
  Fiscal 2003 exceeded $100,000 and any individual who would have satisfied these
  criteria but for the fact that the individual was not serving as an officer
  at the end of Fiscal 2003 (collectively the Named Executive Officers).
  The information is presented in accordance with applicable Canadian and U.S.
  regulations regarding reporting financial information on individual persons.

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|Named Executive Officers    |         |  |        |  |                 
|--------------------------- | ------- |  | ------ |  | ----------------
|                            |         |  |        |  | Other Annual    
|Name/Position               | Salary  |  | Bonus  |  | Compensation (1)
|                            | ($)     |  | ($)    |  | ($)             
|Wayne J. Babcock            |         |  |        |  |                 
|President & CEO             | 152,310 |  | Nil    |  | 2,491,351       
|Donald K. Umbach            |         |  |        |  |                 
|Vice President & COO        | 143,096 |  | Nil    |  | 2,491,351       
|David G. Grohs,             |         |  |        |  |                 
|Vice-President, Production  | 140,805 |  | 53,000 |  | Nil             
|Michael A. Bardell,         |         |  |        |  |                 
|CFO & Corporate Secretary   | 104,300 |  | 20,000 |  | Nil             
|James R. Britton (3)        |         |  |        |  |                 
|Vice-President, Exploration | 79,363  |  | Nil    |  | 2,491,351       

(1)The Other Annual Compensation paid during
  reporting periods is in respect to payments made to certain of the Named Executive
  Officers pursuant to royalty agreements previously approved by our shareholders.
  During the period January 1 to July 7, 2003, amounts paid pursuant to each of
  the three overriding royalty agreement was $319,351. On July 7, 2003, we repurchased
  from each the three Named Executive Officers, gross overriding royalty interests
  that previously burdened total current and future corporate production by 1%
  (for a total of 3%). We paid an aggregate of $6,516,000 to eliminate these obligations
  under the three overriding royalty agreements. The aggregate purchase price
  was paid by the issuance of 1,050,666 of our common shares and the payment of
  $1,000,000 in cash. The number of common shares was based on a deemed price
  of $5.25 per share, such price having been determined according to a daily volume-weighted
  average price formula applied to recent trading as required by the rules of
  the Toronto Stock Exchange.(2)We have a formalized stock option plan for the discretionary
  granting to the Named Executive Officers of incentive stock options that are
  exercisable for shares of our Common Stock.(3)Mr. Britton retired effective October 27, 2003.

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
  required 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 explained further in Note 1 above, we purchased these royalty agreements
  from Messrs. Babcock, Umbach and Britton in July 2003, thereby ending the overriding
  royalty arrangements with such persons.

During Fiscal 2003, we paid
  cash compensation to our officers in the aggregate sum of $2,650,927. This amount
  includes a one-time cash payment of $1,958,053 and a one-time issuance of shares
  valued at $5,516,000 pursuant to the repurchase of the gross overriding royalty
  agreements as described in Note 1 above.

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

Other than employment contracts
  described above, we had, as of the end of Fiscal 2003, no compensatory plan
  or arrangement in respect of compensation received or that may be received by
  the Named Executive Officers to compensate Named Executive Officers in the event
  of the termination of employment (resignation, retirement, change of control)
  or in the event of a change in responsibilities following a change in control,
  where in respect of the Named Executive Officer the value of such compensation
  exceeds $100,000, a threshold required by Canadian securities regulations.

The following table sets forth
  all compensation for services in all capacities to us for Fiscal 2003 in respect
  of each of the non-employee directors. None of our directors have service contracts
  with the company relating to their serving as a director, and none of the directors
  will receive benefits upon termination of their position as a director. Directors
  who are a member of an official standing committee (i.e. audit, reserves audit,
  corporate governance,

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compensation or any other) are granted 5,000 options annually
  and directors who chair such committees are granted 2,500 options annually in
  addition to those identified above.

|Compensation of Non-Employee Directors |            |       |             
|-------------------------------------- | ---------- | ----- | ------------
|                                       |            |       | Other Annual
|Name/Position                          | Salary (1) | Bonus | Compensation
|John A. Greig                          | Nil        | Nil   | Nil         
|                                       |            |       |             
|Jonathan A. Rubenstein                 | Nil        | Nil   | Nil         
|                                       |            |       |             
|David J. Jennings (3)                  | Nil        | Nil   | Nil         
|                                       |            |       |             
|John Lagadin                           | Nil        | Nil   | Nil         
|                                       |            |       |             
|                                       |            |       |             
|William B. Thompson (4)                | Nil        | Nil   | Nil         
|                                       |            |       |             
|                                       |            |       |             

(1) During Fiscal 2003 , 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 that are exercisable
  for shares of our Common Stock. The options indicated above were granted pursuant
  to that plan. (3)At our Annual General Meeting held on August 25, 1999, our shareholders
  approved the nomination of David J. Jennings for election as director for a
  three-year term. He was subsequently re-appointed at the 2002 Annual General
  Meeting for an additional three-year term. Mr. Jennings performs legal work
  on our behalf as a Barrister and Solicitor with the firm of Irwin, White &
  Jennings (1999). Mr. Jennings Fiscal 2003 legal fees amounted to approximately
  $67,000 (Cdn.). (4) Mr. Thompson was appointed as a director through board nomination
  on December 17, 2002 and was subsequently re-elected at the 2003 Annual General
  Meeting for an additional three-year term.

Non-Cash Compensation to Directors,
  Officers and Employees

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

The following table shows the number of shares
  of Common Stock subject to outstanding stock options held by our directors or
  officers, as a group as of May 5, 2004.

|Stock Options Outstanding as of May 5, 2004 |                |                    
|------------------------------------------- | -------------- | -------------------
|(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          | 30,000             
|February 27, 2007                           | $1.75          | 210,000            
|June 18, 2008                               | $5.30          | 45,000             
|July 15, 2008                               | $4.66          | 125,000            
|August 21, 2008                             | $5.43          | 30,000             
|April 30, 2009                              | $4.75          | 65,000             
|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                                       |                | 1,283,750          

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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, 2004.

|Stock Options Outstanding as of May 5, 2004 |                |                    
|------------------------------------------- | -------------- | -------------------
|(Non-Directors/Non-Officers)                |                |                    
|                                            |                | Number of Shares of
|Expiry Date                                 | Exercise Price | Common Stock       
|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          | 20,250             
|April 14, 2006                              | $2.25          | 30,800             
|February 27, 2007                           | $1.75          | 88,334             
|February 16, 2008                           | $3.80          | 30,000             
|July 15, 2008                               | $4.66          | 108,500            
|Total                                       |                | 375,884            

Stock Options Granted to and Exercised by Named Executive Officers

During Fiscal 2003 there were
  a total of 125,000 options granted to the Named Executive Officers as a group.

During Fiscal 2003, there were
  a total of 623,000 options exercised by named executive officers, employee directors
  and non-employee directors.

The following table sets forth
  details of the number of stock options held as of May 5, 2003 by each of the
  Named Executive Officers. The table also sets forth the May 5, 2004 value of
  unexercised in-the-money options on an aggregated basis. We have no stock appreciation
  rights outstanding.

|Stock Options Held by Named Executive Officers |                              
|---------------------------------------------- | -----------------------------
|                                               |                              
|                                               | Number of Unexercised Options
|                                               | Held At May 5, 2004          
|Name                                           | Exercisable / Unexercisable  
|Wayne J. Babcock                               | 140,000/55,000               
|Donald K. Umbach                               | 140,000/55,000               
|David G. Grohs                                 | 43,333/26,667                
|Michael A. Bardell                             | 76,667/33,333                
|James R. Britton                               | 70,000/25,000                

(1)Value of unexercised in-the-money options calculated
  using the closing price of our shares of Common Stock on the Toronto Stock Exchange
  on May 5, 2004, less the exercise price of in-the-money stock options.

Options and Bonus Shares

During the year ended December
  31, 2003, members of the Compensation Committee recommended, and the Board of
  Directors approved, the granting of 138,500 options to our employees. There
  were no option re-pricings during the year ended December 31, 2003. The Compensation
  Committee also affirmed a recommendation from our President and our Chief Operating
  Officer for the distribution of a special cash bonus to our Vice President,
  Production reflecting his exceptional performance. At the 2003 Annual General
  Meeting, a stock bonus plan was approved by our shareholders that provides for
  up to 50,000 bonus shares in the aggregate to be issued to eligible directors,
  officers or employees. There were no bonus shares issued in Fiscal 2003 pursuant
  to the 2003 Incentive Stock Bonus Plan. The Committee intends to continue a
  conservative approach to the issuance of these bonus shares.

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

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Board Practices

Term of Office

At our annual general meeting
  held on August 27, 1998, our shareholders approved amending our Articles of
  Incorporation to provide that approximately one-third of the members of the
  Board of Directors be elected annually for three-year terms. At the end of Fiscal
  2003, we had seven directors. The terms of all seven expire at the annual meeting
  of shareholders as follows:

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

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

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

Committees: Audit, Audit Reserves, Compensation
  and Corporate Governance

The following table sets forth
  details relating to the composition of our Board Committees as of the end of
  Fiscal 2003.

|List of Directors, Committees and Committee Members |            |            |              |         
|--------------------------------------------------- | ---------- | ---------- | ------------ | --------
|                                                    |            |            |              |         
|                                                    |            | Corporate  |              | Audit   
|                                                    | Full Board | Governance | Compensation | Reserves
|Non-Employee Directors                              |            |            |              |         
|John Greig                                          | x          | x          | x            |         
|Jonathan Rubenstein                                 | x          | x          | Chair        |         
|David Jennings                                      | x          | Chair      | x            |         
|John Lagadin                                        | x          |            |              | Chair   
|Bill Thompson                                       | x          |            |              | x       
|                                                    |            |            |              |         
|Employee Directors                                  |            |            |              |         
|Wayne Babcock                                       | Chair      |            |              |         
|Don Umbach                                          | x          |            |              |         

Audit Committee - the Audit Committee
  is mandated to:

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

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

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

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

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

Royalty Interests Acquired

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

Salaries and Bonuses

Since 1999 the Compensation
  Committee has retained the services of William M. Mercer Inc. (Mercer)
  of Calgary, Alberta to conduct thorough executive compensation reviews. As a
  result of the Mercer report received in 2003, the Compensation Committee found
  that the salary levels of our Companys executives were outside and
  below the ranges of salaries for executives in comparable positions in the peer
  group of oil and gas producing companies. As a result of this, and following
  the closing of our acquisition of the aforementioned royalties, the Committee
  resolved to increase the base annual salary levels of each of the President
  and Chief Executive Officer, and the Vice President and Chief Operating Officer
  from $116,800 to $190,000 and from $116,800 to $171,000, respectively, and also
  to institute discretionary bonus provisions in the employment arrangements for
  these officers. The distribution of such bonuses by the committee for Fiscal
  2003 has not yet been considered.

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After giving effect to these
  adjustments, the salary of each of these two executives remain below the mean
  of the salaries paid for the same positions by a selected peer group of companies.
  No subsequent increases, other than cost of living increases, have been made
  to the salary levels for the year ended December 31, 2003.

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

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

Retirement Payment

Mr. James R. Britton was paid a retirement amount
  of about $19,000 to reward him at the end of his many years of service to us.

Indebtedness and Material Interest of Committee
  Members

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

Employees

As of December 31, 2003, we
  employed twenty-one people full time in our Richmond, British Columbia office,
  as compared with sixteen as of December 31, 2002. The persons employed are the
  President & CEO, the Vice President & COO, the CFO & Corporate Secretary,
  the Vice President, Production and seventeen persons occupied with technical
  support, company and joint venture accounting, financial reporting, office management
  and land administration. None of our employees are related.

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

Beneficial Share Ownership

The following
  table sets forth the Common Stock ownership of each of our directors and officers.
  All ownership shown is of record and reflects beneficial ownership as of May
  5, 2004, and represents the number of shares of Common Stock beneficially owned,
  directly or indirectly, or controlled by the person listed. Unless otherwise
  indicated, such shares are held directly.

|Beneficial Share Ownership of Directors and Officers                 |                                |                    
|-------------------------------------------------------------------- | ------------------------------ | -------------------
|                                                                     |                                | Number of Shares of
|Name                                                                 | Position                       | Common Stock(1)    
|Wayne J. Babcock                                                     | President & CEO, Director      | 1,293,607          
|Donald K. Umbach                                                     | Vice President & COO, Director | 680,254            
|John A. Greig                                                        | Director                       | 263,077            
|Jonathan A. Rubenstein                                               | Director                       | 178,313            
|David J. Jennings                                                    | Director                       | 157,500            
|John Lagadin                                                         | Director                       | 95,000             
|William B. Thompson                                                  | Director                       | 60,000             
|Michael A. Bardell                                                   | CFO & Corporate Secretary      | 298,041            
|David G. Grohs                                                       | Vice President, Production     | 58,333             
|(1)Includes options exercisable within 60 days of
      May 4, 2004. |                                |                    

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Item 7. Major Shareholders and Related Party Transactions

Major Shareholders

To the best of our knowledge,
  no person beneficially owns, directly or indirectly, or exercises control or
  direction over shares constituting more than five percent of the voting rights
  of our shares, other than our President and CEO, Wayne Babcock, who beneficially
  owns approximately 5.5% of our outstanding shares. Over the past three fiscal
  years, Mr. Babcock increased his beneficial ownership by 741,314 shares of Common
  Stock. Of this increase, 413,714 shares or 56% were acquired upon our repurchase
  in Fiscal 2003 of his gross overriding royalty interest that previously burdened
  our total current and future production by 1% (see Note 7(d) to our Financial
  Statements). The balance of the increase in his beneficial ownership was mostly
  due to his exercise of stock options.

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

Related Party Transactions

Please see the description of
  our Gross Overriding Royalty Agreements in Item 10  Material Contracts
  and Agreements  Gross Overriding Royalty Repurchase 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, 2004 to the date of this Report, no significant change has occurred.

Item 9. The Offer and Listing

Markets and Price History of the Stock

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

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

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

|                                  | TSX (in Cdn $) |      | NASDAQ SmallCap(in
      U.S. $)
|--------------------------------- | -------------- | ---- | --------------------------------
|                                  | High           | Low  | High                            
|Fiscal 2003                       | 6.49           | 3.10 | 4.97                            
|Nine-Month Fiscal Transition 2002 | 4.45           | 1.60 | 3.05                            
|Fiscal 2002                       | 2.63           | 1.55 | 1.75                            
|Fiscal 2001                       | 3.00           | 1.55 | 2.06                            
|Fiscal 2000                       | 2.05           | 1.44 | 1.50                            
|Fiscal 1999                       | 1.90           | 1.40 | 1.38                            

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

|Prices of Common Stock            |      | TSX (in Cdn $) | NASDAQ Small Cap (in U.S. $)
|--------------------------------- | ---- | -------------- | ----------------------------
|                                  | High | Low            | High                        
|Fiscal 2003                       |      |                |                             
|Q1 ended March 31, 2003           | 4.10 | 3.22           | 3.00                        
|Q2 ended June 30, 2003            | 5.75 | 3.91           | 4.25                        
|Q3 ended September 30, 2003       | 5.93 | 4.15           | 4.25                        
|Q4 ended December 31, 2003        | 6.49 | 4.61           | 4.97                        
|Nine-Month Fiscal Transition 2002 |      |                |                             
|Q1 ended June 30, 2002            | 2.00 | 1.60           | 1.25                        
|Q2 ended September 30, 2002       | 2.25 | 1.60           | 1.39                        
|Q3 ended December 31, 2002        | 4.45 | 1.90           | 3.05                        
|Fiscal 2002                       |      |                |                             
|Q1 ended June 30, 2001            | 2.52 | 1.69           | 1.75                        
|Q2 ended September 30, 2001       | 2.35 | 1.55           | 1.55                        
|Q3 ended December 31, 2001        | 2.05 | 1.56           | 1.31                        
|Q4 ended March 31, 2002           | 2.05 | 1.60           | 1.34                        

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

|         | TSX (in Cdn $) |      | NASDAQ SmallCap(in U.S. $)
|-------- | -------------- | ---- | --------------------------
|Year     | High           | Low  | High                      
|Apr/2004 | 5.00           | 4.40 | 3.83                      
|Mar/2004 | 5.00           | 4.10 | 3.90                      
|Feb/2004 | 5.48           | 4.76 | 4.28                      
|Jan/2004 | 6.49           | 4.69 | 5.04                      
|Dec/2003 | 6.49           | 4.75 | 4.97                      
|Nov/2003 | 5.50           | 4.61 | 4.17                      

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.

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|--------------------------------------- | 
|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 [i.e. shareholders].
  Such remuneration may be in addition to any salary or other remuneration paid
  to any officer or employee of the Company as such who is also a Director.

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

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

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

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

Rights, preferences
  and restrictions attaching to each class of shares

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

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

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

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

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

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

Actions necessary to change
  the rights of holders of our stock

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

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

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

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

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

Limitations on rights
  to own securities of the Company

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

The Act requires a non-Canadian
  who is a WTO investor (defined below) making a direct acquisition of control
  of a Canadian business with assets of $237 million or more (for 2004), to file
  an application for review with Investment Canada, a federal agency created by
  the Act. At present we would constitute a Canadian business under the Act, although
  at present our asset value does not exceed the $237 million threshold. Under
  the Act, control of a corporation is deemed to be acquired through the acquisition
  of a majority of the voting shares of a corporation, and is presumed to be acquired
  where one-third or more, but less than a majority, of the voting shares of a
  corporation are acquired, unless it can be established that the Company is not
  controlled in fact through the ownership of voting shares.

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

For the purposes of determining
  who is a WTO investor when an acquisition of a Canadian business
  occurs, the Act provides a definition that includes: an individual who is a
  national or a lawful permanent resident of a state that is a member of the World
  Trade Organization (WTO) (which includes the United States of America
  and an additional 146 member states); a government or government agency of a
  WTO state; an entity that is controlled by a WTO investor-controlled entity
  (other than a Canadiancontrolled entity); and a corporation, limited partnership
  or trust which is not a Canadian-controlled entity of which two-thirds of its
  Board of Directors, general partners or trustees, as the case may be, are Canadian
  or WTO investors.

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

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

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

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

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

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

Provisions of our Memorandum or
  Articles governing the ownership threshold above whichshareholder
  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 thematters addressed above in this Item 10.

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

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

Material Contracts and Agreements

During Fiscal 2003, we entered
  into three contracts to repurchase certain gross overriding royalty interests
  from three of our officers. Each royalty interest burdened our share of gross
  production of all petroleum substances by 1% on lands acquired by us since June
  1, 1986 for two of the three officers and June 1, 1987 for the third officer.
  Apart from these three overriding royalty repurchase agreements, all other contracts/agreements
  we entered into during Fiscal 2003 are considered to be immaterial and in the
  ordinary course of our business.

Gross Overriding Royalty
  Repurchase Agreements dated July 6, 2003, repurchased by us from each
  of three of our officers. The gross overriding royalty interests previously
  burdened our total current and future corporate production by 3%. The Company
  paid an aggregate of $6,516,000 to eliminate the obligations under the three
  overriding royalty agreements. The aggregate purchase price was paid by our
  issuance of 1,050,666 shares of our Common Stock and the payment of $1,000,000
  in cash. The number of shares of our Common Stock issued was based on a price
  of $5.25 per share, such price having been determined according to a daily volume-weighted
  average price formula applied to recent trading as required by the rules of
  the Toronto Stock Exchange.

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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"), enacted on June 20, 1985, as amended, as further
  amended by the North American Free Trade Agreement (NAFTA) Implementation
  Act (Canada) and the World Trade Organization (WTO) Agreement Implementation
  Act, there are no limitations under the laws of Canada, the Province of
  British Columbia or in the charter or any other of our constituent documents
  on the right of non-Canadians to hold and/or vote the Common Stock (see further
  comments under Item 10  Limitations on rights to own securities
  of the Company).

Taxation

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

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

Canadian Federal Income Tax Considerations

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

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

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

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United States Federal
  Income Tax Considerations

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

Dividends

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

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

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

Sale or Exchange of Common
  Stock

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

Foreign Tax Credit

Subject to the limitations set
  forth in the Code, as modified by the Convention, a US holder may elect to claim
  a credit against his or her U.S. federal income tax liability for Canadian income
  tax withheld from dividends received in respect of shares of our Common Stock.
  Holders of our Common Stock and prospective US holders of our Common Stock should
  be aware that dividends we pay generally will constitute passive income
  for purposes of the

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foreign tax credit, which could reduce the amount of foreign
  tax credit available to them. The rules relating to the determination of the
  foreign tax credit are complex. US holders of our Common Stock and prospective
  US holders of our Common Stock should consult their own tax advisors to determine
  whether and to what extent they would be entitled to such credit. Holders who
  itemize deductions may instead claim a deduction for Canadian income tax withheld.

Passive Foreign Investment
  Company Considerations

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

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

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

As an alternative to the QEF
  election, US holders may elect to mark their Common Stock to its market value
  (a "mark-to-market election"). If a valid mark-to-market election is made, the
  electing US holder generally will recognize ordinary income for the taxable
  year an amount equal to the excess, if any, of the fair market value of their
  Common Stock as of the close of such taxable year over the US holder's adjusted
  tax basis in the Common Stock. In addition, the US holder generally is allowed
  a deduction for the lesser of (1) the excess, if any, of the US holder's adjusted
  tax basis in the Common Stock over the fair market value of the Common Stock
  as of the close of the taxable year, or (2) the excess, if any of (A) the mark-to-market
  gains for the Common Stock included in gross income by the US holder for prior
  taxable years, over (B) the mark-to-market losses for Common Stock that were
  allowed as deductions for prior tax years.

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

Financing Exploration
  and Development Drilling Through Canadian Income Tax Incentives

In order to encourage investment
  in the exploration for and development of its mineral deposits, 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. 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

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investment are usually set forth in a "Flow Through Agreement"
  in which the company agrees not to take as an income tax deduction the amount
  of the proceeds expended for exploration and/or development work, but to allow
  the deduction to flow through to the investors. This flow-through
  type of financing is of benefit only to Canadian taxpayers.

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

During Fiscal 2003, Nine-Month
  Fiscal Transition 2002, Fiscal 2002 and Fiscal 2001 we did not raise any flow-through
  funding.

Item 11. Quantitative and Qualitative Disclosures About
  Market Risk

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

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

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

Market risk is the possibility
  that a change in the prices for natural gas, natural gas liquids, condensate
  and oil, foreign currency exchange rates, or interest rates will cause the value
  of a financial instrument to decrease or become more costly to settle. Our financial
  instruments in Fiscal 2003 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.

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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 Fiscal 2003, we sold
  46% of our natural gas to ProGas and 54% into the AECO daily spot market. During
  Nine-Month Fiscal Transition 2002 and Fiscal 2002, we sold 51% and 53% to ProGas,
  respectively, and the balances at 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 (one of the worlds crude
  oil benchmarks followed by market analysts, investors and industry), allowing
  for quality adjustments and location differentials.

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

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

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


Weighted Average Prices and the Effect of Adversity

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

|                            | Weight-Averaged Prices |  |          |  |                                         
|--------------------------- | ---------------------- |  | -------- |  | ----------------------------------------
|Fiscal 2003                 |                        |  | Achieved |  | After Consideration of
      Adversity %
|                            | Final                  |  | Entire   |  |                                         
|                            | Quarter                |  | Period   |  | 10%                                     
|Natural gas ($/mcf)         | 5.73                   |  | 6.56     |  | 5.90                                    
|Natural gas liquids ($/bbl) | 25.58                  |  | 27.68    |  | 24.91                                   
|Crude oil ($/bbl)           | 28.63                  |  | 42.98    |  | 38.68                                   

Impact on Gross Revenues After Consideration of Pricing
  Adversity

The following table demonstrates
  the effects of weight-averaged pricing adversity as applied to our Fiscal 2003
  gross revenues. Our cash flow from operations and earnings before taxes would
  experience the same effects.

|Fiscal 2003         | Weight-Averaged Prices |  |          |  |                                         
|------------------- | ---------------------- |  | -------- |  | ----------------------------------------
|($ 000s)           |                        |  | Achieved |  | After Consideration of
      Adversity %
|                    | Final                  |  | Entire   |  |                                         
|Commodity Type      | Quarter                |  | Period   |  | 10%                                     
|Natural gas         | 7,091                  |  | 30,649   |  | 27,584                                  
|Natural gas liquids | 1,682                  |  | 6,646    |  | 5,981                                   
|Crude oil           | 862                    |  | 9,553    |  | 8,598                                   

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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, 2003 balance of accounts receivable is
  due from fivecustomers, subject to normal credit risk. Further, while
  our largest producing properties during Fiscal 2003 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 three-eighths of a percent per annum. To minimize our exposure
  to rate variability, we occasionally invest a portion of our undrawn borrowing
  capacity in Bankers Acceptances. We are charged a standby fee of one-eighth
  of a percent per annum on our undrawn borrowing capacity.

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

At December 31, 2003, we had
  floating debt outstanding of $13.3 million (December 31, 2002  $11.1 million,
  March 31, 2002 - $14.8 million).

Item 12. Description of Securities Other than Equity Securities

Not applicable.

Part II.

Item 13. Defaults, Dividend Arrearages and Delinquencies

None

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

Shareholder Rights Plan

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

Our Shareholders re-adopted
  a Permitted Bid Shareholder Protection Rights Plan (Rights Plan)
  at our Annual General Meeting on August 23, 2001.

The Rights Plan is designed
  to ensure that all of our shareholders are treated equally if a takeover bid
  is made for our shares of Common Stock, and that sufficient time is available
  for our directors and all shareholders to evaluate fully any offer and pursue
  alternatives to maximize shareholder value. The Rights Plan provides our board
  of directors and shareholders with 60 days, which is longer than provided by
  applicable laws, to fully consider any unsolicited take-over bid without undue
  pressure, to allow our board of directors, if appropriate, to consider other
  alternatives to

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maximize shareholder value and to allow additional time for
  competing bids to emerge. If a bid is made to all shareholders, which is held
  open for at least 60 days and is accepted by shareholders holding more than
  50% of the outstanding common shares, or is otherwise permitted by our board
  of directors, then the Rights Plan will not affect the rights of shareholders.
  Otherwise, all shareholders, except the parties making a take-over bid, will
  be able to acquire a number of additional common shares equal to 100% of their
  existing outstanding holdings at half the market price. Thus, any party making
  a take-over bid not permitted by the Rights Plan could suffer significant dilution.
  The Rights Plan is valid until the first shareholders meeting held after August
  23, 2004.

Item 15. Controls and Procedures

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

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

Item 16(A). Audit Committee Financial Expert

The Board of Directors has determined
  that Mr. Jonathan Rubenstein and Mr. William Thompson possess the necessary
  attributes for designation as the Company's audit committee financial experts
  and the Board has designated Mr. Jonathan Rubenstein and Mr. William Thompson
  as its audit committee financial experts.

Item 16(B). Code of Ethics

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

Item 16(C). Principal Accountant Fees and Services

Reserved

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

Reserved

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

Reserved

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Part III.

Item 17. Financial Statements

|Auditors Report                                                                                                                | F-1
|------------------------------------------------------------------------------------------------------------------------------- | ---
|                                                                                                                                |    
|Balance Sheets as of December 31, 2003 and December
      31, 2002                                                              | F-2
|                                                                                                                                |    
|Statements of Operations and Retained Earnings for
      Fiscal 2003 and the periods ended December 31, 2002 and March 31, 2002 | F-3
|                                                                                                                                |    
|Statements of Cash Flows for December 31, 2003 and
      the periods ended December 31, 2002 and March 31, 2002                 | F-4
|                                                                                                                                |    
|Notes to Financial Statements                                                                                                   | F-5

Item 18. Financial Statements

(a)See Item 17.

(b)n/a

Item 19. Exhibits

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

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Signatures

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

Date: May 20, 2004

Dynamic Oil & Gas, Inc.
  By: /s/ Michael A.Bardell Michael A. Bardell
  Chief Financial Officer & Corporate Secretary

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INDEX TO EXHIBITS

|Exhibit
      Numbers | EXHIBITS                                                                                                                                                                                                                                                                                                                    
|--------------------- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                      |                                                                                                                                                                                                                                                                                                                             
|1(a) and 2(a)(i)      | Certificate of Incorporation and Articles/By-laws (1)                                                                                                                                                                                                                                                                       
|1(b) and 2(a)(ii)     | Certificate of Increase of Authorized Capital of the Company and Name
      Change (2)                                                                                                                                                                                                                                      
|1(c) and 2(a)(iii)    | Amendment to Articles of Incorporation re Staggered Board (5)                                                                                                                                                                                                                                                               
|1(d) and 2(a)(iv)     | Corporate Governance Committee Guidelines (3)                                                                                                                                                                                                                                                                               
|2(a)(v)               | Shareholder Rights Plan Agreement (2)                                                                                                                                                                                                                                                                                       
|4(i)                  | Sour Gas Processing and Transportation Agreement
        by and between ATCO Gas Services Ltd. And Fletcher Challenge Energy Canada
        and Dynamic Oil Limited, dated July 11, 1997 (1)                                                                                                                                
|(ii)                  | Gas Purchase Contract by and between Dynamic Oil Limited and Progas Limited,
      dated November 1, 1997 (1)                                                                                                                                                                                                               
|(iii)                 | Sweet Gas Processing and Transportation Agreement
        between ATCO Gas Services Ltd. and Dynamic Oil & Gas Inc., dated December
        16, 1998 (2)                                                                                                                                                                    
|(iv)                  | Purchase and Sale Agreement between Fletcher Challenge
        Oil & Gas Inc. and Dynamic Oil & Gas, Inc. et al, dated June 26,
        2001 (re: acquisition of Fletchers interest in St. Albert property
        by Dynamic, Trioco Resources Inc. and Energy North Inc.) (4)                                            
|(v)                   | Contribution, Mutual Interest and Exclusion Agreement
        between Dynamic Oil & Gas, Inc., Trioco Resources Inc. and Energy
        North Inc. dated June 29, 2001 (re: Joint bidding agreement in connection
        with the Purchase and Sale Agreement of Fletchers St. Albert interest
        described above (4)
|(vi)                  | Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas,
      Inc. and Wayne Babcock (4)                                                                                                                                                                                                                       
|(vii)                 | Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas,
      Inc. and Donald K. Umbach (4)                                                                                                                                                                                                                    
|(viii)                | Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas,
      Inc. and James Britton (4)                                                                                                                                                                                                                       
|(ix)                  | Employment Agreement, dated July 11, 2000 between Dynamic Oil & Gas,
      Inc. and Michael Bardell (4)                                                                                                                                                                                                                     
|(x)                   | Employment Agreement, dated March 5, 2001 between Dynamic Oil & Gas,
      Inc. and David Grohs (4)                                                                                                                                                                                                                         
|(xi)                  | Employment Agreement, dated March 12, 2001 between Dynamic Oil & Gas,
      Inc. and Jonathan White (4)                                                                                                                                                                                                                     
|(xii)                 | Overriding Royalty Agreement dated July 13, 1990 between Dynamic Oil Limited
      and Wayne J. Babcock (4)                                                                                                                                                                                                                 
|(xiii)                | Overriding Royalty Agreement dated July 13, 1990 between Dynamic Oil Limited
      and Donzoil Ltd (4)                                                                                                                                                                                                                      
|(xiv)                 | Overriding Royalty Agreement dated August 31, 1990 between Dynamic Oil
      Limited and James R. Britton (5)                                                                                                                                                                                                               
|(xv)                  | Overriding Royalty Repurchase Agreement dated
      July 6, 2003 between Dynamic Oil & Gas, Inc. and Wayne J. Babcock (6)                                                                                                                                                                                                   
|(xvi)                 | Overriding Royalty Repurchase Agreement dated
      July 6, 2003 between Dynamic Oil & Gas, Inc. and Donzoil Ltd (6)                                                                                                                                                                                                        
|(xvii)                | Overriding Royalty Repurchase Agreement dated
      July 6, 2003 between Dynamic Oil & Gas, Inc. and James R. Britton (6)                                                                                                                                                                                                   

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INDEX TO EXHIBITS continued

|Exhibit Numbers | EXHIBITS                                                                                                                     
|--------------- | -----------------------------------------------------------------------------------------------------------------------------
|                |                                                                                                                              
|12.1            | Rule 13a-14(a)/15d-14(a) Certification of Chief
      Executive Officer (6)                                                  
|12.2            | Rule 13a-14(a)/15d-14(a) Certification of Chief
      Financial Officer (6)                                                  
|13.1            | Section 1350, Certification of Chief Executive
      Officer (6)                                                             
|13.2            | Section 1350, Certification of Chief Financial
      Officer (6)                                                             
|14              | National Instrument 51-101, Canadian Standards
      of Disclosure for Oil and Gas Activities, Form 1, Form 2, and Form 3 (6)

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

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

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Financial Statements

Dynamic Oil & Gas, Inc.December 31, 2003 and 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, 2003 and 2002 and the statements of operations
  and retained earnings and cash flows for the year ended December 31, 2003, the
  nine months ended December 31, 2002 and the year ended March 31, 2002. These
  financial statements are the responsibility of the Companys management.
  Our responsibility is to express an opinion on these financial statements based
  on our audits.

We conducted our audits in accordance with 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, 2003 and 2002 and the results of its operations and its cash flows for the
  year ended December 31, 2003, the nine months ended December 31, 2002 and the
  year ended March 31, 2002 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 and asset retirement obligations
  as explained in note 3, on a basis consistent with that of the preceding year.

|                                                                                              |  |                      
|--------------------------------------------------------------------------------------------- |  | ---------------------
|Vancouver, Canada, 
      March 22, 2004 (except for Note 18, which is as of April 30, 2004). |  | Chartered Accountants

F-1

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

BALANCE SHEETS (in Canadian dollars)

As at December 31

|                                           | 2003       |  | 2002       | 
|------------------------------------------ | ---------- |  | ---------- | 
|                                           | $          |  | $          | 
|                                           |            |  |            | 
|ASSETS[note 5]                             |            |  |            | 
|Current                                    |            |  |            | 
|Accounts receivable [note 11]              | 6,962,387  |  | 6,426,761  | 
|Prepaid expenses                           | 356,449    |  | 351,771    | 
|Income taxes receivable                    |           |  | 131,772    | 
|Total current assets                       | 7,318,836  |  | 6,910,304  | 
|Natural gas and oil interests [notes 3, 4] | 57,083,789 |  | 37,148,539 | 
|Capital assets [note 4]                    | 365,561    |  | 168,366    | 
|                                           | 64,768,186 |  | 44,227,209 | 
|                                           |            |  |            | 
|LIABILITIES AND SHAREHOLDERS EQUITY       |            |  |            | 
|Current                                    |            |  |            | 
|Bank indebtedness                          | 1,386,238  |  | 1,519,923  | 
|Operating loan [note 5]                    | 13,250,000 |  | 11,075,000 | 
|Accounts payable and accrued liabilities   | 11,335,946 |  | 11,133,844 | 
|Income taxes payable                       | 659,519    |  |           | 
|Total current liabilities                  | 26,631,703 |  | 23,728,767 | 
|Asset retirement obligations [note 6]      | 1,587,733  |  | 1,087,223  | 
|Future income tax liability [note 8]       | 5,617,723  |  | 843,581    | 
|Total liabilities                          | 33,837,159 |  | 25,659,571 | 
|Commitments [note 13]                      |            |  |            | 
|                                           |            |  |            | 
|Shareholders equity                       |            |  |            | 
|Share capital [note 7]                     | 27,747,487 |  | 20,720,629 | 
|Contributed surplus [note 7[c]]            | 358,229    |  |           | 
|Retained earnings (deficit)                | 2,825,311  |  | (2,152,991 | 
|Total shareholders equity                 | 30,931,027 |  | 18,567,638 | 
|                                           | 64,768,186 |  | 44,227,209 | 

See accompanying notes

On behalf of the Board:

| | Director |  | Director
| | -------- |  | --------

F-2

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Dynamic Oil & Gas, Inc.

STATEMENTS OF OPERATIONS AND RETAINED EARNINGS (in Canadian dollars)

|                                                        |                  |   | **Nine**         |   |                |  
|------------------------------------------------------- | ---------------- | - | ---------------- | - | -------------- | -
|                                                        | **Year ended**   |   | **months ended** |   | **Year ended** |  
|                                                        | **December 31,** |   | **December 31,** |   | **March 31,**  |  
|                                                        | **2003**         |   | **2002**         |   | **2002**       |  
|                                                        | **$**            |   | **$**            |   | **$**          |  
|                                                        |                  |   |                  |   |                |  
|REVENUE                                                 |                  |   |                  |   |                |  
|Natural gas, liquids and oil sales                      | 46,847,927       |   | 24,122,754       |   | 26,401,872     |  
|Royalties [note 7[d]]                                   | (12,861,990      | ) | (5,521,583       | ) | (6,500,447     | )
|Production costs                                        | (7,010,610       | ) | (5,470,467       | ) | (5,845,958     | )
|                                                        | 26,975,327       |   | 13,130,704       |   | 14,055,467     |  
|Royalty tax credit - Alberta                            | 401,365          |   | 178,098          |   | 159,274        |  
|Royalty credit - British Columbia                       | 121,913          |   |                 |   |               |  
|                                                        | 27,498,605       |   | 13,308,802       |   | 14,214,741     |  
|                                                        |                  |   |                  |   |                |  
|EXPENSES                                                |                  |   |                  |   |                |  
|General and administrative                              | 3,414,751        |   | 1,839,496        |   | 2,347,212      |  
|Interest expense                                        | 724,897          |   | 454,251          |   | 494,685        |  
|Interest income                                         | (11,675          | ) | (1,732           | ) | (22,066        | )
|Accretion of asset retirement obligation [note
      6] | 93,843           |   | 63,876           |   | 55,286         |  
|                                                        | 4,221,816        |   | 2,355,891        |   | 2,875,117      |  
|                                                        |                  |   |                  |   |                |  
|Earnings from operations before the following:          | 23,276,789       |   | 10,952,911       |   | 11,339,624     |  
|Amortization and depletion [note 4]                     | 12,021,474       |   | 6,322,863        |   | 11,956,944     |  
|Exploration expenses                                    | 4,065,885        |   | 1,446,178        |   | 4,646,018      |  
|Gain on sale of natural gas and oil interests           |                 |   | (2,139           | ) | (4,566         | )
|Earnings (loss) before taxes                            | 7,189,430        |   | 3,186,009        |   | (5,258,772     | )
|Income tax expense (recovery) [note 8]                  |                  |   |                  |   |                |  
|- Current                                               | 632,294          |   | 207,000          |   | 57,600         |  
|-
      Future                                          | 1,578,834        |   | 974,703          |   | (1,903,920     | )
|Net earnings (loss)                                     | 4,978,302        |   | 2,004,306        |   | (3,412,452     | )
|                                                        |                  |   |                  |   |                |  
|Deficit, beginning of period - as previously reported   | (2,475,932       | ) | (4,321,539       | ) | (695,279       | )
|Retroactive adjustment for changes in                   |                  |   |                  |   |                |  
|accounting
      policy [note 3[b]]                     | 322,941          |   | 296,298          |   | 189,665        |  
|Deficit, beginning of period - as restated              | (2,152,991       | ) | (4,025,241       | ) | (505,614       | )
|Premium on purchase and cancellation of                 |                  |   |                  |   |                |  
|common
      shares [note 7[e]]                         |                 |   | (132,056         | ) | (107,175       | )
|Retained earnings (deficit), end of period              | 2,825,311        |   | (2,152,991       | ) | (4,025,241     | )
|                                                        |                  |   |                  |   |                |  
|Net earnings (loss) per share [note 9]                  |                  |   |                  |   |                |  
|basic                                                   | 0.23             |   | 0.10             |   | (0.17          | )
|diluted                                                 | 0.23             |   | 0.10             |   | (0.17          | )

See accompanying notes

F-3

---

Dynamic Oil & Gas, Inc.

STATEMENTS OF CASH FLOWS(in Canadian dollars)

|                                                        |                  |   | **Nine**         |   |                |  
|------------------------------------------------------- | ---------------- | - | ---------------- | - | -------------- | -
|                                                        | **Year ended**   |   | **months ended** |   | **Year ended** |  
|                                                        | **December 31,** |   | **December 31,** |   | **March 31,**  |  
|                                                        | **2003**         |   | **2002**         |   | **2002**       |  
|                                                        | **$**            |   | **$**            |   | **$**          |  
|                                                        |                  |   |                  |   |                |  
|OPERATING ACTIVITIES                                    |                  |   |                  |   |                |  
|Net earnings (loss)                                     | 4,978,302        |   | 2,004,306        |   | (3,412,452     | )
|Add (deduct) items not involving cash:                  |                  |   |                  |   |                |  
|Accretion of asset
      retirement obligation [note 6] | 93,843           |   | 63,876           |   | 55,286         |  
|Amortization and
      depletion                        | 12,021,474       |   | 6,322,863        |   | 11,956,944     |  
|Stock based compensation
      [note 3[a]]              | 358,229          |   |                 |   |               |  
|Future income tax
      expense (recovery)              | 1,578,834        |   | 974,703          |   | (1,903,920     | )
|Exploration expenses                                    | 4,065,885        |   | 1,446,178        |   | 4,646,018      |  
|Gain on sale of natural gas and oil interests           |                 |   | (2,139           | ) | (4,566         | )
|                                                        | 23,096,567       |   | 10,809,787       |   | 11,337,310     |  
|Changes in non-cash working capital affecting           |                  |   |                  |   |                |  
|operating
      activities [note 10[a]]                 | 5,197,611        |   | 646,829          |   | (1,558,807     | )
|Cash provided by operating activities                   | 28,294,178       |   | 11,456,616       |   | 9,778,503      |  
|                                                        |                  |   |                  |   |                |  
|FINANCING ACTIVITIES                                    |                  |   |                  |   |                |  
|Bank indebtedness                                       | (133,685         | ) | 677,111          |   | 842,812        |  
|Operating loan                                          | 2,175,000        |   | (3,675,000       | ) | 14,750,000     |  
|Shares issued for cash                                  | 1,510,858        |   |                 |   | 455,420        |  
|Share repurchases                                       |                 |   | (325,948         | ) | (289,793       | )
|Cash provided by (used in) financing activities         | 3,552,173        |   | (3,323,837       | ) | 15,758,439     |  
|                                                        |                  |   |                  |   |                |  
|INVESTING ACTIVITIES                                    |                  |   |                  |   |                |  
|Purchase of capital assets                              | (308,387         | ) | (84,420          | ) | (116,180       | )
|Natural gas and oil interests                           | (22,727,557      | ) | (12,493,116      | ) | (21,994,897    | )
|Exploration expenses                                    | (4,065,885       | ) | (1,446,178       | ) | (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 10[b]]                 | (4,744,522       | ) | 5,888,796        |   | (2,277,861     | )
|Cash used in investing activities                       | (31,846,351      | ) | (8,132,779       | ) | (29,030,390    | )
|                                                        |                  |   |                  |   |                |  
|Decrease in cash and cash equivalents                   |                 |   |                 |   | (3,493,448     | )
|Cash and cash equivalents, beginning of period          |                 |   |                 |   | 3,493,448      |  
|Cash and cash equivalents, end of period                |                 |   |                 |   |               |  
|                                                        |                  |   |                  |   |                |  
|Supplemental disclosures of cash flow information       |                  |   |                  |   |                |  
|Cash paid during the year for:                          |                  |   |                  |   |                |  
|Interest                                                | 555,536          |   | 459,237          |   | 589,549        |  
|Income
      taxes                                      | (150,408         | ) | 760,132          |   | 1,167,720      |  

See accompanying notes

F-4

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

1. DESCRIPTION OF BUSINESS

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting principles

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

Change in fiscal year end

Effective December 31, 2002, the Company changed its fiscal
  year end from March 31 to December 31. The following is a summary of selected
  financial information for the comparative twelve month periods ended December
  31, 2003, 2002 and 2001.

Results of operations and cash flows

|                                                 | **December 31,** |   | **December 31,** |   | **December 31,** |  
|------------------------------------------------ | ---------------- | - | ---------------- | - | ---------------- | -
|                                                 | **2003**         |   | **2002**         |   | **2001**         |  
|Twelve months ended                              | **$**            |   | **$**            |   | **$**            |  
|                                                 | [audited]        |   | [unaudited]      |   | [unaudited]      |  
|                                                 |                  |   |                  |   |                  |  
|Revenue                                          | 46,847,927       |   | 30,730,477       |   | 31,658,397       |  
|Net earnings                                     | 4,978,302        |   | 2,034            |   | 2,449,690        |  
|Net earnings per share                           |                  |   |                  |   |                  |  
|basic                                            | 0.23             |   | 0.02             |   | 0.12             |  
|diluted                                          | 0.23             |   | 0.02             |   | 0.12             |  
|Cash flows                                       |                  |   |                  |   |                  |  
|provided
      by operating activities           | 28,294,178       |   | 15,215,456       |   | 14,949,163       |  
|provided
      by (used in) financing activities | 3,552,173        |   | (4,331,528       | ) | 12,972,031       |  
|used
      in investing activities               | (31,846,351      | ) | (10,900,821      | ) | (29,877,314      | )

F-5

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

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

Use of estimates

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

Natural gas and oil interests

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

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

Natural gas and oil interests are recorded at cost less accumulated
  provisions for potential, amortization and depletion. Natural gas and oil interests
  are assessed periodically for potential impairment on a field-by-field basis.
  Any impairment loss is the difference between the carrying value of the asset
  and its net recoverable amount (undiscounted).

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.

Capital assets

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

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

F-6

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

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.

Asset retirement obligations

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

Revenue recognition

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

Stock-based compensation

The Company grants stock options to employees, directors and
  consultants pursuant to a stock option plan described in note 7(b). The Company
  uses the fair value method of accounting for all stock-based awards granted,
  modified or settled since January 1, 2003 [note 3]. For awards granted, modified
  or settled prior to January 1, 2003, the Company discloses the pro forma effects
  to the net earnings (loss) and net earnings (loss) per share for the period
  as if the fair market value had been used at the date of grant. The pro forma
  information is presented in note 7(c).

F-7

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

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

Foreign currency translation

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

Measurement uncertainty

The amounts recorded for depletion and amortization of natural
  gas and oil interests and asset retirement obligations are based on estimates.
  Assessments for impairments in asset carrying costs are based on 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.

Earnings per share

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

Comparative figures

Certain of the comparative figures have been restated to conform
  to the current periods presentation.

F-8

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

3.   CHANGE IN ACCOUNTING POLICIES

[a] Stock-based compensation

Effective January 1, 2003, the Company early-adopted the amended
  standard of accounting for stock-based compensation as required by CICA Handbook
  section 3870, Stock-based compensation and other stock-based payments
  (CICA 3870). The amended standard has an expanded requirement to
  apply the fair-value based method of accounting for all stock-based payments,
  direct awards of stock and awards that call for settlement in cash and other
  assets. Prior to its amendment, CICA 3870 was first adopted by the Company on
  April 1, 2002. During the period April 1, 2002 to December 31, 2002, the Company
  used the fair-value based method to account for stock options granted to non-employees
  and elected to use the intrinsic value method to account for stock options granted
  to directors and employees under its stock option plan.

Under the fair-value based method, compensation costs attributable
  to all share options are measured at fair value at the grant date and expensed
  over the vesting period with a corresponding increase to contributed surplus.
  Pursuant to the transition rules relating to the amended standard, the expense
  recognized relates to all stock options granted during the year ended December
  31, 2003. Consideration paid for shares on exercise of the share options is
  credited to share capital.

The adoption of the amended standard resulted in the Company
  recognizing an expense of $358,229 or $0.02 per share for the year ended December
  31, 2003 [note 7[c]].

[b] Asset retirement obligations

Effective January 1, 2003, the Company early-adopted the new
  recommendations for accounting for obligations associated with the retirement
  of tangible long-lived assets and the associated asset retirement costs as required
  by CICA Handbook section 3110, Asset Retirement Obligations (CICA
  3110) [see note 6]. CICA 3110 requires liability recognition for retirement
  obligations associated with tangible long-lived assets, such as producing wellsites
  and associated facilities, and includes those for which a company faces a legal
  settlement obligation or has made promissory estoppel.

The estimates of the obligations are based on engineering
  estimates, which consider past experience, current regulations, technology and
  industry standards. The amount of the liability is subject to re-measurement
  at each reporting period. The associated retirement costs are capitalized as
  part of the carrying amount of the long-lived assets and depleted over time
  on a unit-of-production basis. This differs from the prior practice, which involved
  accruing for the estimated removal and site restoration liability through charges
  to earnings over the estimated life of reserves. The Company has applied the
  changes retroactively and prior periods have been restated, for comparative
  purposes. The restatement did not impact the net earnings per share for those
  periods.

F-9

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

3. CHANGE IN ACCOUNTING POLICIES (contd.)

Following is a summary of the after-tax changes reflected
  in the statements of operations and balance sheets presented:

|                                       |              |   | **Nine**     |  |            | 
|-------------------------------------- | ------------ | - | ------------ |  | ---------- | 
|                                       | Year ended   |   | Months ended |  | Year ended | 
|                                       | December 31, |   | March 31,    |  | March 31,  | 
|                                       | 2002         |   | 2002         |  | 2002       | 
|                                       | $            |   | $            |  | $          | 
|                                       |              |   |              |  |            | 
|Net increase (decrease) in earnings    |              |   |              |  |            | 
|before tax                             | (67,733      | ) | 40,046       |  | 160,713    | 
|Net increase (decrease) in future      |              |   |              |  |            | 
|income tax expense                     |             |   | 13,043       |  | 54,030     | 
|Net increase (decrease) in earnings    | (67,733      | ) | 26,643       |  | 106,633    | 
|Assets (natural gas and oil interests) | 859,573      |   | 580,463      |  | 520,449    | 
|Liabilities                            | 377,688      |   | 257,442      |  | 416,829    | 

4. NATURAL GAS AND OIL INTERESTS, AND CAPITAL ASSETS

|                                           |            |  | Accumulated      |  |            | 
|------------------------------------------ | ---------- |  | ---------------- |  | ---------- | 
|                                           |            |  | amortization and |  | Net book   | 
|                                           | Cost       |  | depletion        |  | value      | 
|                                           | $          |  | $                |  | $          | 
|                                           |            |  |                  |  |            | 
|December 31, 2003                          |            |  |                  |  |            | 
|Natural gas and oil interests              | 94,425,822 |  | 37,342,033       |  | 57,083,789 | 
|Furniture, fixtures and computer equipment | 770,910    |  | 405,349          |  | 365,561    | 
|                                           |            |  |                  |  |            | 
|December 31, 2002                          |            |  |                  |  |            | 
|Natural gas and oil interests              | 62,580,290 |  | 25,431,751       |  | 37,148,539 | 
|Furniture, fixtures and computer equipment | 538,153    |  | 369,787          |  | 168,366    | 

At December 31, 2003, costs of $16,238,852 [2002 - $8,796,000]
  related to non-producing assets have been excluded from the calculation of amortization
  and depletion.

In the year ended December 31, 2003, the Company recorded
  asset write-downs of $316,213 [nine-month period ended December 31, 2002 - $445,467;
  year ended March 31, 2002 - $6,783,248] 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.

F-10

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

5. OPERATING LOAN

During 2003, the Companys bank, the National Bank of
  Canada, increased to $25,000,000 from $21,000,000, the amount made available
  to the Company under a revolving, demand credit facility. Principal balances
  outstanding bear interest at prime plus 3/8% (bank prime rate at December 31,
  2003 - 4.5%; December 31, 2002 - 4.5%). They are collateralized by a general
  assignment of book debts and a floating charge debenture of $38,000,000 covering
  all the assets of the Company. The effective average interest paid during the
  year ended December 31, 2003 was 5.1% [during the nine-month period ended December
  31, 2002 - 5.0%; year ended March 31, 2002 - 4.7%]. A standby fee of 0.125%
  per annum is levied on the unused portion of the facility and is included in
  interest expense.

6. ASSET RETIREMENT OBLIGATION

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

|                                                 | December 31, |  | December 31, |  | March 31, | 
|------------------------------------------------ | ------------ |  | ------------ |  | --------- | 
|                                                 | 2003         |  | 2002         |  | 2002      | 
|                                                 | $            |  | $            |  | $         | 
|                                                 |              |  |              |  |           | 
|Asset retirement obligation, beginning of period | 1,087,223    |  | 956,559      |  | 776,711   | 
|Liabilities incurred                             | 406,667      |  | 66,788       |  | 124,562   | 
|Accretion expense                                | 93,843       |  | 63,876       |  | 55,286    | 
|Asset retirement obligation, end of period       | 1,587,733    |  | 1,087,223    |  | 956,559   | 

The total undiscounted amount of estimated cash flows required
  to settle the obligation is $3,308,669 [for the nine-months ended December 31,
  2002 - $2,109,750; year ended March 31, 2002 - $2,304,984], which has been discounted
  using an average credit-adjusted risk free rate of 6.6%. These payments are
  expected to be made over the next 53 years with the majority of costs incurred
  between 2018 and 2020.

F-11

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

7. 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, December 31, 2002                   | 20,272,530 |  | 20,720,629 | 
|Stock options exercised                      | 871,582    |  | 1,510,858  | 
|Shares issued to repurchase gross overriding |            |  |            | 
|royalty interests
      [note 7[d]]          | 1,050,666  |  | 5,516,000  | 
|Balance, December 31, 2003                   | 22,194,778 |  | 27,747,487 | 

[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 non-employees
  with a maximum term of five years. Those granted prior to February 28, 2001
  vest upon date of grant; those granted on February 28, 2001 and thereafter,
  vest in equal amounts over three years from the date of grant.

In addition, options granted to the Companys outside
  directors prior to June 19, 2003 had a maximum term of ten years and those granted
  on June 19, 2003 and thereafter, have a maximum term of five years. All options
  granted to outside directors vest upon date of grant.

During the year ended December 31, 2003, options issued totaled
  421,000 [268,500 to either inside directors, officers, employees or non-employees;
  152,500 to outside directors]. The exercise price of each option granted under
  the plan equals the amount designated in the individual agreement, which is
  based on the fair value of the stock at the date of grant.

F-12

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

7. SHARE CAPITAL (contd.)

A summary of the status of the Companys stock option
  plan as of December 31, 2003 is presented below:

|                          | December 31, |   | December 31, |  | March 31, | 
|------------------------- | ------------ | - | ------------ |  | --------- | 
|                          | **2003**     |   | 2002         |  | 2002      | 
|                          | Number       |   | Weighted     |  | Number    | 
|                          | of           |   | average      |  | of        | 
|                          | shares       |   | option price |  | shares    | 
|                          | #            |   | $            |  | #         | 
|                          |              |   |              |  |           | 
|Outstanding at beginning  |              |   |              |  |           | 
|of period                 | 2,077,750    |   | 1.83         |  | 1,930,250 | 
|Granted                   | 421,000      |   | 4.61         |  | 147,500   | 
|Exercised                 | (871,582     | ) | 1.73         |  |          | 
|Forfeited                 | (11,334      | ) | 2.83         |  |          | 
|Outstanding at period end | 1,615,834    |   | 2.61         |  | 2,077,750 | 
|Options exercisable at    |              |   |              |  |           | 
|period end                | 1,081,667    |   | 2.33         |  | 1,641,250 | 

Exercise prices for the options outstanding as of December
  31, 2003 ranged from $1.45 to $5.43 per share. These options have a weighted
  average remaining contractual life of 4.33 years.

At December 31, 2003 the following stock options were outstanding
  and exercisable:

|            |  | Options outstanding |  | Options exercisable
|----------- |  | ------------------- |  | -------------------
|            |  |                     |  | Weighted           
|            |  | Number of           |  | average            
|Exercise    |  | shares under        |  | exercise           
|price       |  | option              |  | price              
|$           |  | #                   |  | $                  
|            |  |                     |  |                    
|1.00 - 1.49 |  | 45,000              |  | 1.45               
|1.50 - 1.99 |  | 588,334             |  | 1.73               
|2.00 - 2.49 |  | 549,500             |  | 2.12               
|2.50 - 2.99 |  | 15,000              |  | 2.95               
|3.50 - 3.99 |  | 42,500              |  | 3.83               
|4.00 - 4.99 |  | 65,000              |  | 4.10               
|4.50 - 4.99 |  | 235,500             |  | 4.66               
|5.00 - 5.49 |  | 75,000              |  | 5.35               
|            |  | 1,615,834           |  | 2.61               

F-13

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

7.   SHARE CAPITAL (contd.)

[c] Pro forma net earnings - fair value based method of
  accounting for stock options

During the year ended December 31, 2003, the Company used
  the fair-value based method to account stock options granted to directors, employees
  and non-employees, resulting in a decrease to earnings and a corresponding increase
  to contributed surplus of $358,229. During the nine-month period ended December
  31, 2002, the Company used the same method to expense only those stock options
  granted to non-employees. The following table shows pro forma net earnings and
  net earnings per common share had the Company applied the fair-value based method
  of accounting for all stock options outstanding:

|                                       |              | Nine months 
|-------------------------------------- | ------------ | ------------
|                                       | Year ended   | ended       
|                                       | December 31, | December 31,
|                                       | 2003         | 2002        
|                                       | $            | $           
|                                       |              |             
|Net earnings:                          |              |             
|as reported                            | 4,978,302    | 2,004,306   
|pro forma                              | 4,856,567    | 1,798,630   
|Basic net earnings per common share:   |              |             
|as reported                            | 0.23         | 0.10        
|pro forma                              | 0.23         | 0.09        
|Diluted net earnings per common share: |              |             
|as reported                            | 0.23         | 0.10        
|pro
      forma                        | 0.22         | 0.09        

F-14

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

7. SHARE CAPITAL (contd.)

The Black-Scholes options valuation model was used to estimate
  the fair value of stock options. In addition, option valuation models require
  the input of highly subjective assumptions including the expected stock price
  volatility. As the Companys director and employee stock options may 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 stock options. The fair value of option grants using the
  Black-Scholes model is estimated on the date of grant using the following weighted-average
  assumptions:

|                        |              |  | Nine months  | 
|----------------------- | ------------ |  | ------------ | 
|                        | Year ended   |  | ended        | 
|                        | December 31, |  | December 31, | 
|                        | 2003         |  | 2002         | 
|                        | $            |  | $            | 
|                        |              |  |              | 
|Dividend yield          | 0%           |  | 0%           | 
|Expected volatility     | 51%          |  | 57%          | 
|Risk-free interest rate | 4%           |  | 5%           | 
|Expected lives          | 3 years      |  | 3 years      | 

The weighted average fair value per share of stock options
  granted during the year ended December 31, 2003 was $1.78 [nine-month period
  ended December 31, 2002 - $0.91].

[d] Repurchase of gross overriding royalty interests

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

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

The gross overriding royalty expense pursuant to the agreements,
  was $752,362 during the period January 1 to July 7, 2003 [nine-month period
  ended December 31, 2002 - $681,493; year ended March 31, 2002 - $745,994].

F-15

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

7. SHARE CAPITAL (contd.)

The repurchased overriding royalty interest included in natural
  gas and oil interests in these financial statements is $9,711,308. This carrying
  value is comprised of the aggregate repurchase price of $6,516,000 paid to the
  vendors, plus the related future income taxes of $3,195,308 which require recognition
  in accordance with current accounting rules under CICA Handbook section 3465.

[e] 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 | Authorized share
|-------------------------------- | ----------------
|Commencement                     | Termination     
|                                 |                 
|1-May-02                         | 31-Mar-03       
|9-Apr-01                         | 31-Mar-02       

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

|                                         | Year ended   |  | Nine months ended |  | Year ended |  
|---------------------------------------- | ------------ |  | ----------------- |  | ---------- | -
|                                         | December 31, |  | December 31,      |  | March 31,  |  
|                                         | 2003         |  | 2002              |  | 2002       |  
|                                         | #            |  | $                 |  | #          |  
|                                         |              |  |                   |  |            |  
|Bid termination date: 31-Mar-03          |             |  |                  |  | (189,700   | )
|Bid termination date: 31-Mar-02          |             |  |                  |  |           |  
|                                         |             |  |                  |  | (189,700   | )
|Average purchase price                   |             |  |                   |  | 1.72       |  
|Recorded as an increase of deficit       |              |  |                  |  |            |  
|Recorded as a reduction of share capital |              |  |                  |  |            |  

|                                         | Year ended   |  | Nine months ended |  | Year ended |  
|---------------------------------------- | ------------ |  | ----------------- |  | ---------- | -
|                                         | December 31, |  | December 31,      |  | March 31,  |  
|                                         | 2003         |  | 2002              |  | 2002       |  
|                                         | #            |  | $                 |  | #          |  
|                                         |              |  |                   |  |            |  
|Bid termination date: 31-Mar-03          |             |  |                  |  | (189,700   | )
|Bid termination date: 31-Mar-02          |             |  |                  |  |           |  
|                                         |             |  |                  |  | (189,700   | )
|Average purchase price                   |             |  |                   |  | 1.72       |  
|Recorded as an increase of deficit       |              |  |                  |  |            |  
|Recorded as a reduction of share capital |              |  |                  |  |            |  

F-16

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

8. INCOME TAXES

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

|                                                 | **December 31,** |   | **December 31,** |  
|------------------------------------------------ | ---------------- | - | ---------------- | -
|                                                 | **2003**         |   | **2002**         |  
|                                                 | **$**            |   | **$**            |  
|                                                 |                  |   |                  |  
|Long term future tax assets (liabilities):       |                  |   |                  |  
|CCA in excess of
      book depreciation         | (5,843,546       | ) | (1,015,300       | )
|Finance charges                                  | 100              |   | 1,000            |  
|Provision for asset
      retirement obligations | 225,723          |   | 170,719          |  
|Net future tax (liabilities) assets              | (5,617,723       | ) | (843,581         | )

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

|                                          | Year ended   |   | Nine months ended |  | Year ended
|----------------------------------------- | ------------ | - | ----------------- |  | ----------
|                                          | December 31, |   | December 31,      |  | March 31, 
|                                          | 2003         |   | **2002**          |  | 2002      
|                                          | $            |   | %                 |  | $         
|                                          |              |   |                   |  |           
|Tax at combined federal and               |              |   |                   |  |           
|provincial rates                          | 2,962,000    |   | 41.20             |  | 1,350,000 
|Tax effect of:                            |              |   |                   |  |           
|Non-deductible expenses                   | 1,929,000    |   |                   |  | 898,400   
|Income not taxable                        | (165,400     | ) |                   |  | (70,500   
|Resource allowance                        | (2,218,342   | ) |                   |  | (1,021,197
|Large corporation tax in excess of surtax | 90,000       |   |                   |  | 25,000    
|Effect of changes in tax rates            | (386,130     | ) |                   |  |          
|                                          | 2,211,128    |   |                   |  | 1,181,703 

9. NET EARNINGS PER SHARE

Basic net earnings (loss) per share were calculated on the
  basis of the weighted average number of shares outstanding for the year ended
  December 31, 2003 of 21,393,902 [the nine-month period ended December 31, 2002
  - 20,357,153; year ended March 31, 2002 - 20,365,031]. The weighted average
  number of shares outstanding for the diluted calculation for the year ended
  December 31, 2003 was 21,947,801 [nine-month period ended December 31, 2002
  - 20,554,231; year ended March 31, 2002 - 20,466,543].

F-17

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

9. NET EARNINGS PER SHARE (contd.)

|                                   | Year ended   |  | Nine months ended |  | Year ended |  
|---------------------------------- | ------------ |  | ----------------- |  | ---------- | -
|                                   | December 31, |  | December 31,      |  | March 31,  |  
|                                   | 2003         |  | 2002              |  | 2003       |  
|                                   | $            |  | $                 |  | $          |  
|                                   |              |  |                   |  |            |  
|Numerator                          |              |  |                   |  |            |  
|Net earnings (loss) for the period | 4,978,302    |  | 2,004,306         |  | (3,412,452 | )
|                                   |              |  |                   |  |            |  
|Denominator                        |              |  |                   |  |            |  
|Weighted average number of common  |              |  |                   |  |            |  
|shares outstanding                 | 21,393,902   |  | 20,357,153        |  | 20,365,031 |  
|Effect of dilutive stock options   | 553,899      |  | 197,078           |  | 101,512    |  
|                                   | 21,947,801   |  | 20,554,231        |  | 20,466,543 |  
|                                   |              |  |                   |  |            |  
|Basic earnings (loss) per share    | 0.23         |  | 0.10              |  | (0.17      | )
|Diluted earnings (loss) per share  | 0.23         |  | 0.10              |  | (0.17      | )

10. CHANGES IN NON-CASH WORKING CAPITAL BALANCES

[a] Changes affecting operating activities comprise:

|                                         | December 31, |   | December 31, |   | March 31,  |  
|---------------------------------------- | ------------ | - | ------------ | - | ---------- | -
|                                         | 2003         |   | 2002         |   | 2003       |  
|                                         | $            |   | $            |   | $          |  
|                                         |              |   |              |   |            |  
|Accounts receivable                      | 1,299,019    |   | (968,683     | ) | (581,264   | )
|Prepaid expenses                         | (4,678       | ) | 13,456       |   | (124,761   | )
|Accounts payable and accrued liabilities | 3,111,979    |   | 2,155,188    |   | (728,998   | )
|Income taxes payable                     | 791,291      |   | (553,132     | ) | (123,784   | )
|                                         | 5,197,611    |   | 646,829      |   | (1,558,807 | )

F-18

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

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

[b] Changes affecting investing activities comprise:

|                                         | December 31, |   | December 31, |  | March 31,  |  
|---------------------------------------- | ------------ | - | ------------ |  | ---------- | -
|                                         | 2003         |   | 2002         |  | 2003       |  
|                                         | $            |   | $            |  | $          |  
|                                         |              |   |              |  |            |  
|Accounts receivable                      | (1,834,645   | ) | 521,453      |  | (953,434   | )
|Accounts payable and accrued liabilities | (2,909,877   | ) | 5,367,343    |  | (1,324,427 | )
|                                         | (4,744,522   | ) | 5,888,796    |  | (2,277,861 | )

11. 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, 2003, and 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, 2003 nine
  customers represent 80% of the accounts receivable balance, [December 31, 2002
  - five customers represent 56% of accounts receivable].

F-19

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

12. RECONCILIATION TO US 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:

|                                                      |              |   | Nine months  |   |            |  
|----------------------------------------------------- | ------------ | - | ------------ | - | ---------- | -
|                                                      | Year ended   |   | ended        |   | Year ended |  
|                                                      | December 31, |   | December 31, |   | March 31,  |  
|                                                      | 2003         |   | 2002         |   | 2003       |  
|                                                      | $            |   | $            |   | $          |  
|                                                      |              |   |              |   |            |  
|Net earnings (loss) under Canadian GAAP               | 4,978,302    |   | 2,004,306    |   | (3,412,452 | )
|Amortization and depletion [a]                        |             |   | (65,471      | ) | (140,399   | )
|Accretion of asset retirement obligation [a]          |             |   | 40,242       |   | 35,936     |  
|Options issued for services [b]                       |             |   | (3,108       | ) |           |  
|Write-down on natural gas and oil                     |              |   |              |   |            |  
|properties [c]                                        | (125,580     | ) | (209,160     | ) | (140,465   | )
|Income taxes [d]                                      |             |   |             |   | 708,800    |  
|Net earnings (loss) before cumulative                 |              |   |              |   |            |  
|effect of change
      in accounting principle        |              |   |              |   |            |  
|under
      U.S. GAAP                                 | 4,852,722    |   | 1,766,809    |   | (2,948,580 | )
|Cumulative effect of change in accounting             |              |   |              |   |            |  
|principle,
      net of applicable taxes [a]          | 133,276      |   |             |   |           |  
|Net earnings (loss) under U.S. GAAP after             |              |   |              |   |            |  
|cumulative effect
      of change in accounting       |              |   |              |   |            |  
|principle                                             | 4,985,998    |   | 1,766,809    |   | (2,948,580 | )
|                                                      |              |   |              |   |            |  
|Net earnings (loss) per common share under U.S. GAAP, |              |   |              |   |            |  
|before change in accounting policy                    |              |   |              |   |            |  
|basic                                                 | 0.23         |   | 0.09         |   | (0.14      | )
|diluted                                               | 0.22         |   | 0.09         |   | (0.14      | )
|                                                      |              |   |              |   |            |  
|Net earnings (loss) per common share under U.S. GAAP, |              |   |              |   |            |  
|after change in accounting policy                     |              |   |              |   |            |  
|basic                                                 | 0.23         |   | 0.09         |   | (0.14      | )
|diluted                                               | 0.23         |   | 0.09         |   | (0.14      | )

F-20

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

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

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

|                                  | **December 31** |  | **December 31** | 
|--------------------------------- | --------------- |  | --------------- | 
|                                  | **2003**        |  | **2002**        | 
|                                  | Canadian        |  | U.S.            | 
|                                  | GAAP            |  | GAAP            | 
|                                  | $               |  | $               | 
|                                  |                 |  |                 | 
|Future income tax liability [d]   |                |  |                | 
|Natural gas and oil interests [c] | 57,083,789      |  | 56,901,789      | 
|Share capital [b, e]              | 27,747,487      |  | 28,720,580      | 
|Retained earnings (deficit)       |                 |  |                 | 
|[a, b, c, d, e]                   | 2,825,311       |  | 1,331,150       | 

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

F-21

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

|12. | RECONCILIATION TO US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
      (contd.)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|[b] | Stock-based compensation
      Prior to the adoption of CICA 3870, on April 1, 2002,
        no compensation expense was recognized under Canadian GAAP when stock
        options were issued to directors, employees or non-employees. This resulted
        in a U.S. GAAP difference for the years ended March 31, 2002 as the Company
        had adopted the disclosure-only provisions of Statement of Financial Accounting
        Standards No. 123, Accounting for Stock-Based Compensation
        for stock based awards to employees and directors, which were adopted
        subsequently in the December 31, 2002 financial statements for Canadian
        GAAP under the original disclosure requirements of 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 year ended March 31,
        2002 consistent with the provisions of SFAS No. 123, the Companys
        net loss and net loss per share would have been increased to the pro forma
        amounts indicated below:

| |                                              | **Year ended** |  
| | -------------------------------------------- | -------------- | -
| |                                              | **March 31,**  |  
| |                                              | **2002**       |  
| |                                              | **$**          |  
| |                                              |                |  
| | Net earnings (loss)                          |                |  
| | as reported                                  | (3,412,452     | )
| | pro forma                                    | (3,249,470     | )
| | Basic net earnings (loss) per common share   |                |  
| | as reported                                  | (0.17          | )
| | pro forma                                    | (0.16          | )
| | Diluted net earnings (loss) per common share |                |  
| | as reported                                  | (0.17          | )
| | pro
      forma                              | (0.16          | )

F-22

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

|**12.** | RECONCILIATION TO US GENERALLY ACCEPTED ACCOUNTING
        PRINCIPLES (contd.)
      For the year ended December 31, 2003, and 2002, the
        net earnings (loss) that would be disclosed for SFAS No. 123 is consistent
        with the amounts shown in note 7[c]. The weighted average assumptions
        used in the Black-Scholes valuation (refer to note 7[c] for discussion
        of the model) for the year ended March 31, 2002 were as follows:
|------- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      | **Year ended** | 
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | -------------- | 
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      | **March 31,**  | 
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      | **2002**       | 
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      | **$**          | 
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |                | 
|    | Dividend yield                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       | 0%             | 
|    | Expected volatility                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  | 57%            | 
|    | Risk-free interest rate                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              | 5%             | 
|    | Expected lives                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       | 3 years        | 
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|[c] | Under both Canadian and
        US GAAP, property, plant and equipment must be assessed for potential
        impairments. Under U.S. GAAP, if the sum of the expected future cash flows
        (undiscounted and without interest charges) is less than the carrying
        amount of the asset, then an impairment loss (the amount by which the
        carrying amount of the asset exceeds the fair value of the asset) should
        be recognized. Fair value is calculated as the present value of estimated
        expected future cash flows. As disclosed in note 1, under Canadian GAAP,
        the impairment loss is the difference between the carrying value of the
        asset and its net recoverable amount (undiscounted). The resulting differences
        in recorded carrying values of impaired assets result in further differences
        in amortization and depletion expense in subsequent years. The CICA has
        adopted a new standard effective for 2004 that will eliminate this Canadian/US
        GAAP difference.
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|[d] | 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 U.S. GAAP. There remains,
        however, a difference between Canadian and U.S. GAAP, as Canadian GAAP
        requires that future income tax balances be adjusted to reflect substantively
        enacted rates rather than the currently legislated tax rates used to account
        for deferred income taxes under U.S. GAAP.                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|[e] | Share issue costs are charged
        directly to retained earnings under Canadian GAAP and to share capital
        under U.S. GAAP. The total share issue costs charged to share capital
        were $570,961.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   

F-23

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

|12.                                                                                                                                                                                                                            | RECONCILIATION TO US GENERALLY ACCEPTED ACCOUNTING PRINCIPLES
      (contd.)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|                                                                                                                                                                                                                               |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|[f]                                                                                                                                                                                                                            | New accounting pronouncements
      In January 2003, the FASB issued Interpretation No.
        46 Consolidation of Variable Interest Entities (FIN No. 46R)
        (revised December 2003). FIN No. 46R clarifies the application of Accounting
        Research Bulletin No. 51, Consolidated Financial Statements, to only certain
        entities in which equity investors do not have the characteristics of
        a controlling financial interest or do not have sufficient equity at risk
        for the entity to finance its activities without additional subordinated
        financial support from other parties. FIN No. 46R applies immediately
        to variable interest entities created after January 31, 2003, and the
        variable interest entities obtained after that date. It applies at the
        end of the first annual reporting period beginning after June 15, 2003,
        to variable interest in which an enterprise holds a variable interest
        which was acquired before February 1, 2003. Adoption of FIN No. 46R on
        January 1, 2004 does not impact the Companys financial position
        or results of operations.
      A similar guideline has been introduced in Canada, Accounting
        Guideline 15 Consolidation of Variable Interest Entities.
        This guideline applies to annual and interim periods beginning on or after
        November 1, 2004.
|                                                                                                                                                                                                                               |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|13. COMMITMENTS The Company
        has entered into an operating lease in respect of its office premises.
      The minimum payments under this lease commitment, including estimated
        operating costs are as follows:

|     |  | $      
|---- |  | -------
|     |  |        
|2004 |  | 202,905
|2005 |  | 208,461
|2006 |  | 202,905
|2007 |  | 208,461
|2008 |  | 89,364 
|     |  | 912,096

F-24

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Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2003

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 renegotiation.

15. SUBSEQUENT EVENT

On April 30, 2004, we entered into a bought-deal financing
  agreement with both Octagon Capital Corporation as lead underwriter and Raymond
  James Ltd. Pursuant to the terms of the agreement, we have agreed to issue,
  by way of private placement 2,000,000 flow-through shares at $5.60 each on a
  firm underwriting basis. As well, at the option of the underwriters, exercised
  at least one business day before closing, we have agreed to issue 400,000 common
  shares at $4.55 each. If the underwriters exercise their option, the total gross
  proceeds of the offering will be $13,020,000.

The net proceeds of the share offering will be used to accelerate
  our continued exploration and development of our core natural gas properties
  at Cypress/Chowade and Orion in northeast British Columbia. Proceeds from the
  flow-through shares will be used to incur qualifying Canadian Exploration Expense
  (CEE) as defined in the Income Tax Act (Canada) and we will renounce,
  for the 2004 taxation year, such CEE in favour of the original holders of the
  flow-through shares in an amount equal to the issue price for each flow-through
  share. Closing is subject to normal closing conditions including obtaining required
  regulatory approvals and is scheduled to occur on or about May 19, 2004.

F-25

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