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

FORM 20-F

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

OR

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 Number0-17551

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

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

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

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

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

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

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

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

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

1



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TABLE OF CONTENTS

|                  |                                                                                    | Page
|----------------- | ---------------------------------------------------------------------------------- | ----
|                  |                                                                                    |     
|Glossary of Terms | 3                                                                                 
|                  |                                                                                    |     
|Part I.           |                                                                                    |     
|Item 1.           | Identity of Directors, Senior Management
      and Advisers                        | 7   
|Item 2.           | Offer Statistics and Expected Timetable                                            | 7   
|Item 3.           | Key Information                                                                    | 7   
|Item 4.           | Our Information                                                                    | 15  
|Item 5.           | Operating and Financial Review and
      Prospects                                 | 41  
|Item 6.           | Directors, Senior Management and Employees                                         | 62  
|Item 7.           | Major Shareholders and Related Party
      Transactions                            | 73  
|Item 8.           | Financial Information                                                              | 73  
|Item 9.           | The Offer and Listing                                                              | 73  
|Item 10.          | Additional Information                                                             | 74  
|Item 11.          | Quantitative and Qualitative Disclosures
      About Market Risk                   | 81  
|Item 12.          | Description of Securities Other than
      Equity Securities                       | 83  
|                  |                                                                                    |     
|Part II.          |                                                                                    |     
|Item 13.          | Defaults, Dividend Arrearages and Delinquencies                                    | 84  
|Item 14.          | Material Modifications to the Rights
      of Security Holders and Use of Proceeds | 84  
|Item 15.          | Controls and Procedures                                                            | 84  
|Item 16(A).       | Audit Committee Financial Expert                                                   | 85  
|Item 16(B).       | Code of Ethics                                                                     | 85  
|Item 16(C).       | Principal Accountant Fees and Services                                             | 85  
|Item 16(D).       | Exemption from the Listing Standards
      for Audit Committees                    | 85  
|Item 16(E).       | Purchases of Equity Securities by the
      Issuer and Affiliated Purchasers       | 85  
|                  |                                                                                    |     
|Part III.         |                                                                                    |     
|Item 17.          | Financial Statements                                                               | 86  
|Item 18.          | Financial Statements                                                               | 86  
|Item 19.          | Exhibits                                                                           | 86  

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

3

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

4

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

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

6

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Part I.

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

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

Item 1. Identity of Directors, Senior Management and Advisers

Not
  applicable.

Item 2. Offer Statistics and Expected Timetable

Not
  applicable.

Item 3. Key Information

Selected Financial Data

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

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

7

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

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

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

8

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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    |   |                |   |        |  
|----------------------------- | ----------- | - | -------- |  | -------- | - | -------------- | - | ------ | -
|                              | As at       |   | December |  | December |   |                |   |        |  
|                              | December 31 |   | 31       |  | 31       |   | As at March 31 |  
|($ 000’s)                     | 2004        |   | 2003     |  | 2002     |   | 2002           |   | 2001   |  
|                              |             |   |          |  |          |   |                |   |        |  
|Balance Sheets                |             |   |          |  |          |   |                |   |        |  
|Future income tax asset       | -           |   | -        |  | -        |   | 371            |   | -      |  
|Future income tax liability   | -           |   | -        |  | 541      |   | -              |   | 3,532  |  
|                              |             |   |          |  |          |   |                |   |        |  
|Natural gas and oil interests | 56,726      |   | 56,902   |  | 36,236   |   | 30,150         |   | 21,679 |  
|Share capital *               | 38,725      |   | 28,721   |  | 21,694   |   | 21,883         |   | 21,610 |  
|(Deficit) retained earnings   | (10,949     | ) | 1,331    |  | (3,636   | ) | (5,422         | ) | (2,356 | )

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

Dividends

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

9

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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 March 15, 2005 was CDN $1.21 per U.S. $1.00.

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

Exchange Rates for Canadian Versus U.S. Dollars

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

Capitalization and Indebtedness

Not
  applicable.

Reasons for the Offer and Use of Proceeds

Not
  applicable.

Risk Factors

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

Exploration and Development Risks

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

Replacement of Reserves

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

10

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

Estimating of Reserves and Future Net Cash Flows
  Risk

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

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

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

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

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

Dependence on One Major Property

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

Limited Financial Resources

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

11

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

Commodity
  Price Fluctuations

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

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

Dependence
  on Key Personnel

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

Drilling
  Plans Subject to Change

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

Potential
  Variability in Quarterly Operating Results

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

12

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Government
  Regulation and Environmental Matters

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

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

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

Competition
  and Business Risk Management

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

Risks
  Pertaining to Acquisitions and Joint Ventures

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

Shortage
  of Supplies and Equipment

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

Interruption
  From Severe Weather

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

Limited
  Operating History

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

13

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

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

Dependence
  on Third-Party Pipelines

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

Availability
  of Natural Gas Supply

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

Operating
  Hazards and Uninsured Risks

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

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

Restoration,
  Safety and Environmental Risk

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

14

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

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

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

Kyoto
  Protocol Risk

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

Item 4. Our Information

Our History and Development

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

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

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

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

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

15

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

|(1) | We follow the successful efforts method of accounting,
        whereby costs of drilling an unsuccessful well are recorded as exploration
        expense when it becomes known the well did not result in a discovery of
        proved reserves or where one year has elapsed since the completion of
        drilling and near- term efforts to establish proved reserves are not foreseeable,
        intended, or in our control.                                                                                                                                                                                                                                                                                                                                     
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) | As at December 31, 2004, exploratory well-drilling
        costs of $8.7 million remain capitalized on our balance sheet. These
        costs relate to seven wells. Various projects are planned in Fiscal 2005
        to determine if proved reserves can be assigned to each of the wells.
        The wells are as follows: three at Cypress/Chowade ($4.9 million);
        two at Orion ($3.4 million); one at Sandgren ($0.3 million); and
        one at Peavey/Morinville ($0.1 million). Drilling operations were
        completed on six of the wells in Fiscal 2004 and on the remaining well
        in Fiscal 2002. The Fiscal 2002 well, at Peavey/Morinville, was assigned
        proved reserves and is expected to commence production in Fiscal 2005.
|   
|(3) | On July 7, 2003, we repurchased from three of our
        officers their gross overriding royalty interests for an aggregate of
        $6.5 million. The aggregate purchase price was paid by the issuance
        of 1.1 million shares of our common stock and the payment of $1.0
        million in cash. The repurchased overriding royalty interest of $9.7
        million shown above is comprised of the aggregate repurchase price of
        $6.5 million paid to the sellers, plus the related future income taxes
        of $3.2 million, which require recognition in accordance with current
        accounting rules under Canadian GAAP. (For further details, see Note 6[d]
        to our Financial Statements under Item 17 to this Report).         

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

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

Capital Investment Program in Fiscal 2004

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

16

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

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

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

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

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

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

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

British
  Columbia
  Cypress/Chowade–During the year, we invested $8.5
  million to drill five wells and to complete an untested zone in an existing
  wellbore. Our working interests in these wells were: one at 100% working interest;
  three at 50%; and two at 30%. Of the five wells that were drilled, three were
  completed as cased and standing natural gas wells and two were unsuccessful.
  We also participated in the construction of an 8” 19-kilometer pipeline,
  most of which was at a 40% working interest.

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

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

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

17

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

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

Fiscal
  2005 – Budgeted Capital Investment Program

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

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

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

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

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

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

18

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

Recent
  Material Events

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

Share
  Repurchases

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

Business Overview

General

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

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

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

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

Concentration
  of Commodities

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

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

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

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

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

Concentration
  of Operations

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

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

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

Revenue
  Breakdown

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

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

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

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Natural Gas, Natural Gas Liquids and Crude Oil Revenue

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

Seasonality
  and Raw Materials

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

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

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

Marketing

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

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

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

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

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

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

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Supply
  Contracts or Agreements

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

Competition

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

Governmental
  Regulations

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

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

Properties,
  Plant and Equipment

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

|Alberta           | British Columbia | Saskatchewan   
|----------------- | ---------------- | ---------------
|St. Albert        | Westlock         | Cypress/Chowade
|Halkirk           | Simonette        | Orion          
|Peavey/Morinville | Wimborne         | Fraser Valley  
|Alexander         | Quirk Creek      |                
|Stanmore          |                  |                

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

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Land Holdings (acres) 
  As at December 31, 2004

|                      | Developed |  | Undeveloped |  | Total   |  | Weighted
|--------------------- | --------- |  | ----------- |  | ------- |  | --------
|Area                  | Gross     |  | Net         |  | Gross   |  | Net     
|Alberta               |           |  |             |  |         |  |         
|St. Albert            | 8,901     |  | 5,873       |  | 3,938   |  | 2,228   
|Halkirk               | 3,840     |  | 3,456       |  | 2,880   |  | 2,880   
|Peavey/Morinville     | 6,467     |  | 4,708       |  | 3,776   |  | 2,290   
|Wimborne              | 2,560     |  | 1,760       |  | 7,115   |  | 5,995   
|Other                 | 3,527     |  | 2,690       |  | 9,920   |  | 6,352   
|                      | 25,295    |  | 18,487      |  | 27,629  |  | 19,745  
|British Columbia      |           |  |             |  |         |  |         
|Cypress/Chowade       | 10,978    |  | 4,925       |  | 45,697  |  | 14,986  
|Orion                 | 5,340     |  | 4,005       |  | 61,274  |  | 42,797  
|Fraser
      Valley   | -         |  | -           |  | 54,502  |  | 18,278  
|                      | 16,318    |  | 8,930       |  | 161,473 |  | 76,061  
|Saskatchewan          |           |  |             |  |         |  |         
|Mantario East         | 967       |  | 745         |  | 2,928   |  | 2,206   
|Flaxcombe             | 40        |  | 30          |  | 6,085   |  | 3,153   
|Sandgren              | 680       |  | 655         |  | 1,903   |  | 713     
|Rapdan                | 160       |  | 14          |  | -       |  | -       
|Elmore                | 162       |  | 8           |  | -       |  | -       
|                      | 2,009     |  | 1,452       |  | 10,916  |  | 6,072   
|Total to Dec 31, 2004 | 43,622    |  | 28,869      |  | 200,018 |  | 101,878 
|Total to Dec 31, 2003 | 32,081    |  | 21,665      |  | 189,290 |  | 100,256 
|Increase (decrease)   | 11,541    |  | 7,204       |  | 10,728  |  | 1,622   
|Increase (decrease) % | 36%       |  | 33%         |  | 6%      |  | 1.6%    

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

Alberta
  Properties

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

Geological
  DescriptionThe
  property is comprised of two reef structures that are associated with 16 separate
  pools of Cretaceous Age natural gas and Devonian Age crude oil that are stacked
  in seven productive formations. Four of the productive formations are natural
  gas and three are crude oil. For purposes of project identification, we refer
  to the two reef structures as the “north pool” and the “south
  pool”. In aggregate, both structures have historically produced in excess
  of 23.7 million barrels of crude oil and 121 billion cubic feet of raw natural
  gas.

Land
  HoldingsWe own 8,101 net acres (12,839 gross) of various crown and freehold
  petroleum and natural gas leases for a weighted average working interest of
  63%. Of our net acreage, 28% is undeveloped.

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

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Wells
  and FacilitiesWe
  own a weighted average 75% working interest in 16 producing gas wells and a
  75% working interest in nine producing oil wells. In addition, we own a 75%
  working interest in one oil battery, two saltwater disposal wells, one solution
  gas plant, one sour gas compressor, two sweet gas compressors and a 13 kilometer,
  6” sour gas pipeline.

Fiscal
  2004 ActivitiesIn
  the north pool we drilled one successful well targeting remaining oil reserves
  in the Leduc D-3 formation and Wabamun D-1 formation. The well is completed
  in both formations and is presently producing oil from the Wabumun D-1 formation.
  Also in the north pool, we drilled one unsuccessful well targeting shallow gas
  in the Belly River and Edmonton formations. In the south pool, we acquired a
  new water disposal well to address future water handling and disposal associated
  with our oil production.

We
  completed untested zones in two existing natural gas wells in the Ostracod formation
  to further optimize sweet gas production. Further, we optimized our sweet gas
  compressor and upgraded our salt-water disposal facilities.

Fiscal
  2005 OutlookOur
  Fiscal 2005 budget continues to focus on production optimization. Two capital
  projects are planned to slow the natural decline rate of oil and gas production
  and to improve operating efficiencies. All projects are geared toward enhanced
  recovery of remaining crude oil and natural gas reserves from known pools.

One
  development well is planned for Fiscal 2005 targeting remaining oil in the Leduc
  D-3 and Wabamun D-1 formations.

Our
  investment at St. Albert includes numerous wells and facilities in close proximity
  to urban areas. For this reason, we will continue our commitment to “STAMP”
  (“St. Albert and Area Multi-Stakeholder Project”), which we helped
  create to bring oil and gas operators, regulators, local government and special
  interest groups together in a forum for open dialog and information exchange.

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

Geological
  DescriptionThis
  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
  HoldingsWe
  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 FacilitiesWe
  own a 100% working interest in four producing Viking gas wells and an 80% working
  interest (before payout of our initial capital expenditures), in three producing
  Viking gas wells. After payout, our working interest will convert to 48%. All
  of our natural gas production is processed at the Maple Glen Gas Plant under
  a custom processing agreement with the plant’s third-party owner.

Fiscal
  2004 ActivitiesDuring the year, production operations were maintained without significant
  capital expenditures.

Fiscal
  2005 OutlookTwo infill development wells are planned and will target sweet natural
  gas in the Viking formation. Our existing gathering system will accommodate
  production from these wells.

Peavey/Morinville
  Peavey/Morinville is located a short distance from our St. Albert field and
  is approximately 19 kilometers north of the City of Edmonton.

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Geological
  DescriptionThe
  area is comprised of natural-gas bearing sandstones and shales of Cretaceous
  Age that are structurally draped over highs in the Leduc D-3 formation.

Land
  HoldingsWe
  own 6,998 net acres (10,243 gross) of petroleum and natural gas rights for a
  weighted average working interest of 68%. Of our total net holdings, 33% is
  undeveloped.

Seismic
  We own a licensed copy of a high quality, 3D seismic database covering 14 square
  kilometers.

Wells
  and FacilitiesWe
  own a weighted average working interest of 77% in six producing natural gas
  wells.

Fiscal
  2004 ActivitiesDuring
  the year, we equipped, tied in and began producing from one natural gas well
  that was drilled in a prior year. All other production operations were maintained
  without significant capital expenditures.

Fiscal
  2005 OutlookTie-in
  of one well and recompletion of another is planned for early in Fiscal 2005.

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

Geological
  DescriptionThe
  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
  HoldingsWe
  own 7,755 net acres (9,675 gross) of petroleum and natural gas rights for a
  weighted average working interest of 80%. Of our total net holdings, 74% is
  undeveloped.

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

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

Fiscal
  2004 ActivitiesWe
  participated at a 50% working interest in the drilling of two wells targeting
  gas in Cretaceous Age formations. Both wells were unsuccessful.

Fiscal
  2005 OutlookOur
  large 3D seismic database has identified multiple undrilled exploration targets
  on our lands. While we have no drilling plans for Fiscal 2005, the area remains
  prospective for third-party farmout opportunities.

British
  Columbia Properties

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

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

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Land
  HoldingsWe
  have crown petroleum and natural gas leases over 19,911 net acres (56,675 gross)
  for a weighted average working interest of 35%. Of our total net acreage, 75%
  is undeveloped.

SeismicOur
  seismic database contains a total of 440 kilometers of licensed, trade 2D seismic
  data, as well as a 100% working interest in 15 kilometers of 2D proprietary
  seismic data.

Wells
  and FacilitiesWe
  have four producing and six cased and standing natural gas wells. In the four
  producing wells, we own a 50% working interest. Our working interests in the
  six cased and standing wells are: 50% in three wells; 100% in one; 30% in one;
  and 20% in the remaining well. In four of the ten wells in which we own a 50%
  working interest, our interest converts to a 30% working interest after payout.
  In addition, we own approximately 40% of an 8” 19-kilometer pipeline that
  crosses beneath the Halfway River and connects Cypress to the Sikanni Gas plant.

We
  split delivery of our 2004 gas production to Cypress Gas Plant and Sikanni Gas
  Plant under separate third party custom processing agreements.

Fiscal
  2004 ActivitiesWe
  participated in drilling five wells and in completing an untested zone in an
  existing wellbore. These wells targeted multi-zone, natural-gas bearing reservoirs
  of Triassic and Mississippian Ages. Our working interests in the wells were:
  one at 100% working interest; three at 50%; and two at 30%. Of the five wells
  that were drilled, three were cased and standing as potential natural gas wells
  and two were unsuccessful. We also participated in the construction of the 8”
  19-kilometer pipeline mentioned above. We also acquired 4,394 net acres (11,544
  gross).

During
  Fiscal 2004, costs related to three wells that were drilled and completed in
  Fiscal 2003 were expensed due to unsuccessful efforts to develop proved reserves.
  Our working interest was 30% in two of these wells and 50% in the third.

Fiscal
  2005 Outlook 
  We plan to participate, at a 30% working interest, in drilling two exploratory
  outpost wells and shooting 15 kilometers of 2D seismic. We also plan to have
  two of our six cased and standing shut-in gas wells on stream in the first quarter
  of Fiscal 2005. The remaining two shut-in wells require further development
  in the area to meet threshold reserves necessary for tie-in.

In
  addition, we have budgeted for our 30% share of the cost to add field compression.
  The current processing capacities of two gas plants in the area are expected
  to meet our processing needs in Fiscal 2005. We will continue to monitor and
  evaluate land acquisition opportunities in the area.

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

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

Geological
  DescriptionThe
  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
  HoldingsWe
  hold under lease 46,802 net acres (66,614 gross) for a weighted average working
  interest of 70%. Approximately 91% of our net holdings are undeveloped.

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Wells
  and FacilitiesWe
  own a 15% gross overriding royalty interest (before payout of our initial capital
  expenditures) in one cased and standing potential Jean Marie gas well and a
  100% working interest in one cased and standing potential Bluesky formation
  gas well. The gross overriding royalty interest will convert to a 50% working
  interest after payout. Both wells are cased and standing and awaiting further
  evaluation and area development. We also own a 100% working interest in two
  other standing cased wells with potential value for purposes of side-track drilling
  or water disposal.

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

Fiscal
  2004 ActivitiesDuring
  the first quarter, we conducted a two-phase 3D seismic program covering 90 square
  kilometers of the property. Interpretation of the seismic data has identified
  several drillable targets on our land. During the third and fourth quarters,
  we drilled three wells targeting gas in the Bluesky and Jean Marie formations.
  Two of these wells were drilled at a 100% working interest and one well was
  drilled at a 50% working interest. One of the 100% wells has been cased as a
  potential standing gas well and the other two wells were unsuccessful.

We
  drilled one well at 100% working interest, targeting gas in the Slave Point
  formation. The Slave Point well was cased and production tested but did not
  produce commercial quantities of gas. The well is a cased and standing gas well
  with further sidetrack drilling potential.

During
  Fiscal 2004, costs related to two wells that were drilled and completed in Fiscal
  2003 were expensed due to unsuccessful efforts to develop proved reserves. Our
  working interest in these two these wells was 100%.

Fiscal
  2005 OutlookWe
  plan to drill one development well in the first quarter, targeting gas in a
  producing Bluesky gas pool that directly offsets company-owned lands. We also
  plan to drill one exploration well in the fourth quarter targeting gas in a
  similar, but separate, Bluesky structure. Both wells are planned at 100% working
  interest.

Fraser
  ValleyThe property is located in the Lower Mainland area of southwest British
  Columbia near Vancouver.

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

Fiscal
  2004 ActivitiesWe
  were inactive in the Fraser Valley area during Fiscal 2004.

Fiscal
  2005 OutlookAreas
  offshore are subject to a restricted-access moratorium for petroleum and natural
  gas activities; however, discussions are underway between the Provincial and
  Federal Governments in regards to lifting the moratorium. The Provincial Government
  has indicated its desire to move forward, and the Federal Government is currently
  conducting a public review to identify environmental and social concerns arising
  from offshore activities along the Pacific West Coast. A final decision on the
  matter is not expected in 2005.

We
  have identified, through analysis of our proprietary onshore 2D seismic data,
  a large structural feature approximately 19 square kilometersin
  size extending offshore. Government-owned gravity data supports our interpretations
  and refers to the feature as the Robert’s Bank Gravity Anomaly. The Geological
  Survey of Canada has assigned the Georgia Basin a reserve estimate of 6.5 trillion
  cubic feet of natural gas. A commercial quantity of gas is yet to be discovered
  in the area. We plan to be inactive in the Fraser Valley in 2005.

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S.W.
  Saskatchewan Properties

Mantario
  East and Surrounding Areas 
  Mantario East is located 30 kilometers southwest of the Town of Kindersley and
  30 kilometers east of the Alberta Border.

Geological
  DescriptionThe area is prospective for multiple Cretaceous, Mississippian and Devonian
  aged sandstone and carbonate reservoirs. Primary targets include natural gas-bearing
  Viking, Upper Mannville and Bakken formations and heavy-oil in the Basal Mannville
  and Birdbear formations.

Land
  HoldingsWe hold under lease 7,524 net acres (12,925 gross) for a weighted average
  working interest of 58%. Approximately 81% of our net holdings are undeveloped.

Well
  and FacilitiesWe have 11 heavy-oil wells at Mantario East, five of which are in production
  and six of which are cased and standing awaiting tie-in. In three of the five
  producing wells, our ownership is a 100% working interest (before payout of
  our original capital expenditures), converting to a 75% working interest after
  payout. In the other two producing and the six cased and standing wells, we
  own a 75% working interest. At Sandgren, we own a 100% working interest before
  payout in one cased and standing gas well that converts to a 75% working interest
  after payout.

Fiscal
  2004 Activities 
  We discovered a new pool of oil in the Basal Mannville at Mantario East. The
  oil is classified by regulation as Basal Mannville heavy-gravity crude. The
  nearest analogs to our heavy-oil discovery is located directly west of us on
  lands owned by others (non-owned) at Marengo, Mantario North, and Mantario East.
  The nearest pools on non-owned lands at Mantario East, have produced over three
  million barrels of heavy-oil from 36 wells in pool sizes of approximately 800
  acres. On our lands at Mantario East, the number of pools and their sizes has
  not yet been determined.

In
  total, we drilled 15 wells in the Mantario area during the third and fourth
  quarters of Fiscal 2004. Of these, five were earning wells drilled at a 100%
  working interest under a farmout agreement and 10 were non-earning wells drilled
  at a 75% working interest with an industry partner. The 15-well drilling program
  resulted in five producing, and six cased and standing heavy crude oil wells,
  one cased and standing natural gas well, and three unsuccessful wells.

Fiscal
  2005 OutlookWe have budgeted to drill four exploration oil and/or natural gas wells
  and to conduct a 15-well, in-fill drilling program targeting Basal Mannville
  oil. We also have budgeted to build a gathering system and a heavy crude oil
  battery facility in Fiscal 2005. We also plan to equip and tie-in two of six
  cased and standing heavy crude oil wells in the first quarter of Fiscal 2005
  and the remaining four in the second quarter. Funds have also been budgeted
  to acquire additional lands and seismic data in the area.

The
  gathering system and heavy crude oil battery is a two-phase construction project.
  Phase I is scheduled for completion by April 1, 2005 and will include tie-in
  of eight heavy crude oil wells to a central battery facility capable of processing
  up to 1,500 barrels per day. Phase II will include tie-in of remaining wells
  as they are drilled and will expand the processing capacity of the battery to
  2,500 barrels per day from an estimated 25 wells.

Other
  Non-Core PropertiesAlberta properties include: Alexander; Stanmore; Westlock; Simonette; and
  Quirk Creek. Saskatchewan properties include: Elmore; and Rapdan. In total,
  these properties comprise 9,064 net acres (13,769 gross) with a weighted average
  working interest of 66%. Of our total net acreage, 71% is undeveloped.

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

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

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

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

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

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

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

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

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

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

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

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

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Estimated
  Reserves Reconciliation

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

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

Net
  Present Values of Reserves

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

|($000’s)                             | Before Income Taxes | After Income Taxes
|------------------------------------ | ------------------- | ------------------
|                                     | Discount Rate       | Discount Rate     
|                                     | 0%                  | 10%               
|Proved                               |                     |                   
|Developed producing                  | 73,892              | 56,325            
|Developed non-producing              | 2,694               | 1,905             
|Undeveloped                          | 3,719               | 2,357             
|Total proved – December 31, 2004     | 80,305              | 60,587            
|Total proved – December 31, 2003     | 121,046             | 87,943            
|Total proved – December 31, 2002 (1) | 164,745             | 109,651           

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

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

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

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

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

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Item 5. Operating and Financial Review and
  Prospects

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

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

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

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

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

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

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

41

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

Operating Results

Summary

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

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

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

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

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

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

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

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

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Executive
  Overview

|                                                        |             |             | Nine-Month     
|------------------------------------------------------- | ----------- | ----------- | ---------------
|                                                        |             |             | Fiscal         
|($ 000’s unless otherwise stated)                       | Fiscal 2004 | Fiscal 2003 | Transition 2002
|Gross revenues                                          | 40,806      | 46,848      | 24,123         
|Cash flow from operations (1)                           | 19,421      | 23,097      | 10,810         
|Cash flow from operations per share ($/share
      )(1) | 0.82        | 1.08        | 0.53           
|Net (loss) earnings                                     | (12,281)    | 4,978       | 2,004          
|Net (loss) earnings per share ($/share)                 | (0.52)      | 0.23        | 0.10           
|                                                        |             |             |                
|Daily average production (boe/d)                        | 2,893       | 3,447       | 3,332          
|Total production (mboe)                                 | 1,059       | 1,258       | 916            
|                                                        |             |             |                
|Capital investment program (2)                          | 36,836      | 35,374      | 13,837         
|Net debt (3)                                            | 25,513      | 19,313      | 16,818         
|Net debt to cash flow (times) (4)                       | 1.3:1       | 0.8:1       | 1.6:1          
|Net debt to cash flow annualized (times)(5)             | 1.3:1       | 0.8:1       | 1.2:1          

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

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

|(2) | For Fiscal 2004, we changed the method of reporting
        capital transactions. We now report capital transactions under the title,
        “Capital Investment Program” instead of the former title,
        “Capital Expenditures”. The difference in methods is that
        Capital Investment Program includes exploration expenses relating to seismic
        and unsuccessful drilling efforts, whereas Capital Expenditures did not.
        Seismic and unsuccessful drilling costs comprise the majority of our Exploration
        expense as reported in our Statements of Operations and Deficit. Capital
        expenditures are reported on our Balance Sheets. When combined, annual
        expenditures for capital, and annual expenses for seismic and unsuccessful
        drilling, represent the sum total of our yearly Capital Investment Program.
        All comparative amounts have been restated accordingly.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(3) | Net debt is working capital. We have no long-term
        debt.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|   
|(4) | Net debt divided by cash flow from operations.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|   
|(5) | Net debt divided by cash flow from operations annualized.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      

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

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

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

43

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

| | • | We spent $4.2 million on the acquisition
        of new lands, over half of which was spent in the Cypress/Chowade area.
        Most of the remainder was spent at Mantario East and on other associated
        Saskatchewan properties;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
| | • | We drilled and completed 28 wells (22.0
        net) and equipped most of them for a total cost of $22.1 million.
        Our overall net working interest drilling success rate was 68%. Of twelve
        wells that targeted natural gas, six were unsuccessful. The other six,
        three at Cypress/Chowade, two at Orion and one at Sandgren, were completed
        as cased and standing wells. We drilled two wells that targeted light/medium
        crude oil at St.Albert, one of which was successful. The remaining 14
        wells targeted heavy crude oil at Mantario East and Flaxcombe, 11 of which
        were either producing or cased and standing as at December 31, 2004. Three
        were unsuccessful;
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
| | • | Our investment in facilities, pipelining
        and other assets grew by $6.7 million. Over 85% of this amount was
        invested in northeast B.C., most of which was for our participation in
        the construction of an 8”, 19 kilometer pipeline at Cypress/Chowade.
        The remaining 15% was primarily for the optimization and upgrading of
        certain production facilities at St. Albert; and                                                                                                                                                                                                                                                                                                                   
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
| | • | We invested $3.7 million on seismic
        data activity, over 87% of which was for a two-phase, 3D seismic program
        covering 90 square kilometers on our early-stage exploration property
        at Orion.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     

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

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

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

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

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

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

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

Financial Results

Cash
  Flow from Operations and Net (Loss) Earnings

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

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

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

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

46

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

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

Fiscal 2003 vs Nine-Month Fiscal Transition 2002

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

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

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

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

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

Daily
  Average Production Rates and Total Production

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

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

47

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

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

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

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

Fiscal
  2003 vs Nine-Month Fiscal Transition 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 to natural declines in reservoir pressures at St.
  Albert and an increase due to the start-up of two new wells at Cypress/Chowade.
  The increase in average daily light/medium crude oil production was due to the
  start-up of two new wells in Fiscal 2003 and of one well in late Nine-Month
  Fiscal Transition 2002. All three wells were at St. Albert.

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

Our
  weighted average light/medium crude oil prices are based on prices for West
  Texas Intermediate (WTI) at Cushing, Oklahoma, adjusted for differentials back
  to Edmonton, Alberta. The Edmonton index par price is for a 40o to
  45ocrude having less than 1⁄2% sulphur content. The actual
  wellhead price for our light/medium crude varies with the quality of the oil
  and the cost of transportation to Edmonton.

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

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

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

48

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

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

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

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

Hedging

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

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

Royalties,
  Mineral Taxes and Royalty Credits

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

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

49

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

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

Production
  Costs

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

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

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

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

Amortization
  and Depletion Expense (A&D)

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

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

50



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

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

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

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

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

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

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

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

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

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

51



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

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

| | Development Wells Drilled
| | -------------------------
| | •                        
| | •                        
| | •                        

| | Exploratory Wells Drilled
| | -------------------------
| | •                        
| | •                        
| | •                        

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

| | Development Wells Drilled
| | -------------------------
| | •                        

| | Exploratory
        Wells Drilled
| | ---------------------------------
| | •                                
| | •                                
| | •                                

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

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

Interest
  Expense - Net

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

52

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

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

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

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

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

General
  and Administrative Expenses (G&A)

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

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

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

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

Income
  Tax Expense

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

53

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

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

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

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

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

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

Critical
  Accounting Policies

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

Reserves
  Estimates

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

54

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Natural
  Gas and Oil Interests

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

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

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

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

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

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

Accounting
  Policy Changes

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

Financial
  Instruments – Disclosure and PresentationIn January 2004, the AcSB amended CICA 3860,
  Financial Instruments – Disclosure and Presentation, to require certain
  obligations that must or may be settled, at the issuer's option, by a variable
  number of the issuer's own equity instruments, to be presented as liabilities.
  These instruments were formerly presented as equity.

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

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

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

55

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

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

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

| | • | Assets classified as trading or available-for-sale
        would be recorded at fair value. Unrealized gains and losses on assets
        classified as trading would be recorded in income. Unrealized gains and
        losses on assets classified as available-for-sale would be recorded in
        comprehensive income.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                                                                                                                                                               
| | • | Held-to-maturity investments and loans
        and receivables would be recorded at amortized cost.                                                                                                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                               
| | • | Financial liabilities that are classified
        as held for trading would be subsequently measured at fair value.                                                                                                                                                                                                           
| |   |                                                                                                                                                                                                                                                                                                                               
| | • | All other financial liabilities would
        be subsequently measured at amortized cost using the effective interest
        method.                                                                                                                                                                                         

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

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

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

| | • | Fair value hedges – hedges of the
        exposure to changes in fair value;                          
| | - | ------------------------------------------------------------------------------------------------------
| |   |                                                                                                       
| | • | Cash flow hedges – hedges of the
        exposure to variability in cash flows; and                   
| |   |                                                                                                       
| | • | Hedges of foreign currency exposures
        of net investments in self-sustaining foreign operations.

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

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

56

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

Changes in Accounting Policies and Estimates, and ErrorsThe AcSB has issued an Exposure Draft with a view to replacing CICA
  1506, Accounting Changes, with a new Section,
  Changes in Accounting Policies and Estimates, and Errors. The Exposure Draft
  proposes the following key changes:

| | • | An entity would be permitted to change
        an accounting policy only when it is required by a primary source of GAAP,
        or when the change results in a reliable and more relevant presentation
        in the financial statements;                                                                            
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                                                                                                                                                           
| | • | Changes in accounting policy would be
        applied retroactively, unless specific transitional provisions in a primary
        source of GAAP permit otherwise or application to comparative information
        is impractical (the standard provides specific guidance as to what is
        considered impractical);
| |   |                                                                                                                                                                                                                                                                                                                           
| | • | Expanded disclosures about the effects
        of changes in accounting policy, estimates and errors on the financial
        statements; and                                                                                                                                                                             
| |   |                                                                                                                                                                                                                                                                                                                           
| | • | Disclosure of new primary sources of
        GAAP that have been issued but have not yet come into effect and have
        not yet been adopted by the entity.                                                                                                                                                            

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

Subsequent EventsThis Exposure Draft proposes several significant enhancements:

| | • | Extension of the period
        during which subsequent events are required to be considered to include
        events that occur between the date of the balance sheet and the date the
        financial statements are authorized for issue (currently, CICA 3820requires consideration to the date of completion of the financial
        statements). "Date of authorization for issue" is defined as the date
        on which those charged with governance, such as the board of directors,
        approve the issuance of the financial statements, including the related
        notes.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | • | Requirement to disclose
        in the financial statements the date when the financial statements were
        authorized for issue and who gave that authorization.                                                                                                                                                                                                                                                                                                                                                                                                                             
| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   
| | • | Requirement to update disclosures
        for adjusting subsequent events in light of new information received up
        to the date of authorization for issue of the financial statements.                                                                                                                                                                                                                                                                                                                                                                                                     

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

U.S. PronouncementsThe 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.

57

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

We continue to assess the applicability of these standards.

Inflation

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

Impact of Foreign Currency Fluctuations

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

Government Policies

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

Liquidity and Capital Resources

Sources and Uses of Cash

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

Operating activities


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

|                                          |             |   |             |   | Nine-Month |   |             |   |             |  
|----------------------------------------- | ----------- | - | ----------- | - | ---------- | - | ----------- | - | ----------- | -
|                                          |             |   |             |   | Fiscal     |   |             |   |             |  
|                                          |             |   |             |   | Transition |   |             |   |             |  
|($ 000’s unless otherwise stated)         | Fiscal 2004 |   | Fiscal 2003 |   | 2002       |   | Fiscal 2002 |   | Fiscal 2001 |  
|                                          |             |   |             |   |            |   |             |   |             |  
|Natural gas                               | $6.67       |   | $6.56       |   | $4.36      |   | $3.81       |   | $6.22       |  
|Light/medium crude
      oil              | $50.03      |   | $42.98      |   | $41.40     |   | $34.33      |   | $43.60      |  
|Heavy crude oil                           | $21.07      |   | -           |   | -          |   | -           |   | -           |  
|                                          |             |   |             |   |            |   |             |   |             |  
|Cash flow from operations;
      (1)and   | 19,421      |   | 23,097      |   | 10,810     |   | 11,337      |   | 18,168      |  
|Capital investment
      program, capital |             |   |             |   |            |   |             |   |             |  
|assets and other                          | (37,410     | ) | (27,102     | ) | (14,022    | ) | (26,753     | ) | (12,432     | )
|Total timing differences                  | (17,989     | ) | (4,005      | ) | (3,212     | ) | (15,416     | ) | 5,736       |  
|                                          |             |   |             |   |            |   |             |   |             |  
|Bank operating indebtedness               | 1,997       |   | 2,041       |   | (2,997     | ) | 15,593      |   | (6,000      | )
|Issuance of common
      shares           | 11,789      |   | 1,511       |   | -          |   | 455         |   | 200         |  
|Repurchases of common
      shares        | -           |   | -           |   | (326       | ) | (290        | ) | (90         | )
|                                          | 13,786      |   | 3,552       |   | (3,323     | ) | 15,758      |   | (5,890      | )
|Changes in non-cash working capital       | (4,203      | ) | (453        | ) | (6,535     | ) | 342         |   | (154        | )

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

58



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

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

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

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

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

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

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

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

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

Cash Requirements

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

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

59

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Cash Management

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

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

Outlook
  for Fiscal 2005

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

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

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

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

| | Development Drilling
        Wells PlannedNatural gas targets
| | -------------------------------------------------------------
| | •                                                            
| | •                                                            
| |                                                              

| | Light/medium crude oil target
| | -----------------------------
| | •                            

| | Heavy crude oil targets
| | -----------------------
| | •                      

| | Other Development Projects PlannedProduction enhancements
| | ---------------------------------------------------------
| | •                                                        
| | •                                                        
| | •                                                        

| | Re-completions (completions of untested zones
      in existing wellbores), and tie-ins of wells previously drilled
| | -------------------------------------------------------------------------------------------------------------------
| | •                                                                                                                  

60

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

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

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

| | Exploratory Drilling Wells PlannedNatural gas targets
| | -----------------------------------------------------
| | •                                                    
| | •                                                    

| | Natural gas, light/medium crude oil or heavy
      crude oil targets
| | --------------------------------------------------------------------
| | •                                                                   

| | Other Exploration Projects PlannedLand acquisitions and seismic data activity
| | -----------------------------------------------------------------------------
| | •                                                                            
| | •                                                                            

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

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

Sensitivity
  Analysis

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

61

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

Contractual
  Obligations and Commitments

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

|                                           |       | Payments or Work Commitments Due
|------------------------------------------ | ----- | --------------------------------
|                                           |       |                                 
|                                           |       | <1                              
|($000’s)                                   | Total | Year                            
|Operating lease obligations (office space) | 696   | 204                             
|Asset retirement obligations (1)           | 4,661 | 129                             
|Total                                      | 5,357 | 333                             

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

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

Off-Balance Sheet Arrangements

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

Item 6. Directors, Senior Management and Employees

Directors and Senior Management

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

62

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

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

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

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

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

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

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

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

63

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Compensation – Fiscal 2004

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

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

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

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

|(1) | The Other Annual Compensation paid during reporting
        periods is in respect to an RRSP contribution made on behalf of the executive
        officer.                                           
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    |                                                                                                                                                                                                      
|(2) | We have a formalized stock option plan for the discretionary
        granting to the Named Executive Officers of incentive stock options that
        are exercisable for shares of our Common Stock.

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

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

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

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

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

|(1) | During Fiscal 2004 , we did not pay any cash compensation
        to our directors (employee and non-employee), in their capacities as such.                                                                                                                                                                                                                                                                                                                                                                                    
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) | We have a formalized stock option plan for the non-discretionary,
        automatic granting of incentive stock options to independent directors
        that are exercisable for shares of our Common Stock. All such grantings
        are allocated at the time of the director’s first election or annually
        based on the director’s participation as a standing committee chair
        or member. The options indicated above were granted pursuant to that plan.                                                  
|   
|(3) | At our Annual General Meeting held on August 25,
        1999, our shareholders approved the nomination of David J. Jennings for
        election as director for a three-year term. He was subsequently re-appointed
        at the 2002 Annual General Meeting for an additional three-year term.
        Mr. Jennings performs legal work on our behalf as a Barrister and Solicitor
        with the firm of Irwin, White & Jennings (1999). Mr. Jennings’
        Fiscal 2004 legal fees amounted to approximately $89,332.

Non-Cash
  Compensation to Directors, Officers and Employees

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

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

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

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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 March 15, 2005.

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

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

Stock Options Granted to and Exercised by Named Executive
  Officers

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

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

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

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

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

Options
  and Bonus Shares

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

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

Board Practices

Term
  of Office

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

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

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

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

Committees:
  Audit, Audit Reserves, Compensation and Corporate Governance

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

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

| | Audit Committee
        - the Audit Committee is mandated to:
| | -------------------------------------------------------------
| |                                                              
| | •                                                            
| | •                                                            
| | •                                                            

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

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

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

Corporate
  Governance Committee


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

71



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

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

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

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

Indebtedness
  and Material Interest of Committee Members

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

Employees

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

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

Beneficial Share Ownership

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

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

|(1) | Includes options exercisable within 60 days of March 15, 2005.
|--- | --------------------------------------------------------------
|    |                                                               
|*   | Less than 1%.                                                 

72

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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% of our outstanding shares. Over
  the past three fiscal years, Mr. Babcock increased his beneficial ownership
  by 526,314 shares of Common Stock.

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

Related Party Transactions

None

Interests of Experts and Counsel

None.

Item 8. Financial Information

Financial Statements and Other Financial Information

Financial
  statements are provided under Item 17.

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

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

Significant Changes

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

Item 9. The Offer and Listing

Markets and Price History of the Stock

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

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

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

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

|                                  | TSX (in Cdn $) | NASDAQ SmallCap (in U.S. $)
|--------------------------------- | -------------- | ---------------------------
|                                  | High           | Low                        
|Fiscal 2004                       | 6.49           | 3.00                       
|Fiscal 2003                       | 6.49           | 3.10                       
|Nine-Month Fiscal Transition 2002 | 4.45           | 1.60                       
|Fiscal 2002                       | 2.63           | 1.55                       
|Fiscal 2001                       | 3.00           | 1.55                       
|Fiscal 2000                       | 2.05           | 1.44                       

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                         
|Fiscal 2004                 |                |                             
|Q1 ended March 31, 2004     | 6.49           | 4.10                        
|Q2 ended June 30, 2004      | 5.03           | 3.94                        
|Q3 ended September 30, 2004 | 5.20           | 3.57                        
|Q4 ended December 31, 2004  | 3.88           | 3.00                        
|Fiscal 2003                 |                |                             
|Q1 ended March 31, 2003     | 4.10           | 3.22                        
|Q2 ended June 30, 2003      | 5.75           | 3.91                        
|Q3 ended September 30, 2003 | 5.93           | 4.15                        
|Q4 ended December 31, 2003  | 6.49           | 4.61                        

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                        
|          |                |                            
|Feb/2005  | 3.40           | 2.95                       
|Jan/2005  | 3.55           | 2.88                       
|Dec/2004  | 3.49           | 3.00                       
|Nov/2004  | 3.80           | 3.05                       
|Oct/2004  | 3.88           | 3.55                       
|Sept/2004 | 4.30           | 3.57                       

Item 10. Additional Information

Notice
  of Articles and Articles

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

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

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

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

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

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

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

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

Rights,
  preferences and restrictions attaching to each class of shares

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

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

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

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

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

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

Actions
  necessary to change the rights of holders of our stock

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

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

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

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

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

Limitations
  on rights to own securities of the Company

Except
  as provided in 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 $250 million
  or more (for 2005), to file an application for review with

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Material Contracts and Agreements

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

Exchange Controls

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

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

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.

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Canadian
  Federal Income Tax Considerations

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

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

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

United
  States Federal Income Tax Considerations

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

Dividends

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

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

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

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Sale
  or Exchange of Common Stock

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

Foreign
  Tax Credit

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

Passive
  Foreign Investment Company Considerations

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

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

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

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

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

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

Financing
  Exploration and Development Drilling Through Canadian Income Tax Incentives

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

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

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

Item 11. Quantitative and Qualitative Disclosures About
  Market Risk

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

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

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

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

81

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

Commodities
  Price Risk

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

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

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

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

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

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

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

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

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

Weighted Average Prices and the Effect of Adversity

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

82

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

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

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

Credit
  Risk

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

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

Interest
  Rate Risk

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

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

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

Item 12. Description of Securities Other than Equity Securities

Not
  applicable.

83

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Part II.

Item 13. Defaults, Dividend Arrearages and Delinquencies

None

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

Shareholder
  Rights Plan

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

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

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

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

Item 15. Controls and Procedures

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

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

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

84

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

Item 16(A). Audit Committee Financial Expert

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

Item 16(B). Code of Ethics

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

Item 16(C). Principal Accountant Fees and Services

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

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

|(1) | Audit related fees are fees for professional services
        provided in connection with the audit of the annual, and quarterly assistance
        with, our financial statements, and services provided in connection with
        other statutory and/or regulatory filings.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) | Tax related fees consisted of fees for services
        regarding federal and provincial tax compliance, filing and reporting.                                                                                                                                                 
|   
|(3) | All other fees in Fiscal 2004 were primarily for
        the assistance with Sarbanes Oxley Section 404 compliance. In Fiscal 2003,
        the fees were for tax advice related to a gross overriding royalty repurchase
        transaction that closed on July 7, 2003.     

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

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

Not
  Applicable

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

Not
  Applicable

85

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Part III.

Item 17. Financial Statements

|Report of Independent Registered Public
      Accounting Firm                                                                                                             | F-1
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---
|                                                                                                                                                                          |    
|Balance Sheets as of December 31, 2004
      and December 31, 2003                                                                                                        | F-2
|                                                                                                                                                                          |    
|Statements of Operations and (Deficit)
      Retained Earnings for the years ended December 31, 2004, December 31,
      2003 and the Nine-Months Ended December 31, 2002 | F-3

|Statements of Cash Flows for the years
      ended December 31, 2004, December 31, 2003 and the Nine-Months Ended December
      31, 2002 | F-4
|----------------------------------------------------------------------------------------------------------------------------------------- | ---
|                                                                                                                                          |    
|Notes to Financial Statements                                                                                                             | F-5

Item 18. Financial Statements

(a)See Item 17.

(b)n/a

Item 19. Exhibits

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

86

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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: March 29, 2005

Dynamic Oil & Gas, Inc.

By /s/ Michael A. Bardell

Michael A. Bardell 
  Chief Financial Officer & Corporate Secretary

87

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Financial Statements

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



---

REPORT OF INDEPENDENT REGISTERED PUBLIC 
  ACCOUNTING FIRM

To the Shareholders of Dynamic Oil & Gas, Inc.

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

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

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

|                                         |                      
|---------------------------------------- | ---------------------
|Vancouver, Canada, 
      March 7, 2005. | Chartered Accountants

F-1


---

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

BALANCE SHEETS(in Canadian dollars)

As at December 31

|                                         | 2004       |   | 2003       | 
|---------------------------------------- | ---------- | - | ---------- | 
|                                         | $          |   | $          | 
|                                         |            |   |            | 
|ASSETS[note 4]                           |            |   |            | 
|Current                                  |            |   |            | 
|Accounts receivable [note 10]            | 7,565,975  |   | 6,962,387  | 
|Prepaid expenses                         | 361,277    |   | 356,449    | 
|Income taxes receivable                  | 541,487    |   | —          | 
|Total current assets                     | 8,468,739  |   | 7,318,836  | 
|Natural gas and oil interests [note 3]   | 56,726,494 |   | 57,083,789 | 
|Capital assets [note 3]                  | 414,913    |   | 365,561    | 
|Future income tax asset [note 7]         | 2,082,092  |   | —          | 
|                                         | 67,692,238 |   | 64,768,186 | 
|                                         |            |   |            | 
|LIABILITIES AND SHAREHOLDERS’ EQUITY     |            |   |            | 
|Current                                  |            |   |            | 
|Bank indebtedness                        | 1,083,000  |   | 1,386,238  | 
|Operating loan [note 4]                  | 15,550,000 |   | 13,250,000 | 
|Accounts payable and accrued liabilities | 17,348,723 |   | 11,335,946 | 
|Income taxes payable                     | —          |   | 659,519    | 
|Total current liabilities                | 33,981,723 |   | 26,631,703 | 
|Asset retirement obligations [note 5]    | 2,555,756  |   | 1,587,733  | 
|Future income tax liability [note 7]     | —          |   | 5,617,723  | 
|Total liabilities                        | 36,537,479 |   | 33,837,159 | 
|Commitments [note 12]                    |            |   |            | 
|                                         |            |   |            | 
|Shareholders’ equity                     |            |   |            | 
|Share capital [note 6]                   | 39,852,368 |   | 27,747,487 | 
|Contributed surplus [note 6[c]]          | 757,689    |   | 358,229    | 
|(Deficit) retained earnings              | (9,455,298 | ) | 2,825,311  | 
|Total shareholders’ equity               | 31,154,759 |   | 30,931,027 | 
|                                         | 67,692,238 |   | 64,768,186 | 

See accompanying notes

On behalf of the Board:

| | /s/ Wayne Babcock | /s/ Donald Umbach
| | ----------------- | -----------------
| | Director          | Director         

F-2

---

Dynamic Oil & Gas, Inc.

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

|                                                  |              |   |              |   | Nine Months  |  
|------------------------------------------------- | ------------ | - | ------------ | - | ------------ | -
|                                                  | Year Ended   |   | Year Ended   |   | Ended        |  
|                                                  | December 31, |   | December 31, |   | December 31, |  
|                                                  | 2004         |   | 2003         |   | 2002         |  
|                                                  | $            |   | $            |   | $            |  
|                                                  |              |   |              |   |              |  
|REVENUE                                           |              |   |              |   |              |  
|Natural gas, liquids and oil sales                | 40,805,507   |   | 46,847,927   |   | 24,122,754   |  
|Royalties                                         | (9,002,506   | ) | (12,861,990  | ) | (5,521,583   | )
|Production costs                                  | (8,940,597   | ) | (7,010,610   | ) | (5,470,467   | )
|                                                  | 22,862,404   |   | 26,975,327   |   | 13,130,704   |  
|Provincial royalty credits                        | 399,223      |   | 523,278      |   | 178,098      |  
|                                                  | 23,261,627   |   | 27,498,605   |   | 13,308,802   |  
|                                                  |              |   |              |   |              |  
|EXPENSES                                          |              |   |              |   |              |  
|General and administrative                        | 3,715,663    |   | 3,414,751    |   | 1,839,496    |  
|Interest expense                                  | 578,112      |   | 724,897      |   | 454,251      |  
|Interest income                                   | (1,836       | ) | (11,675      | ) | (1,732       | )
|Accretion of asset retirement obligation [note 5] | 102,836      |   | 93,843       |   | 63,876       |  
|                                                  | 4,394,775    |   | 4,221,816    |   | 2,355,891    |  
|                                                  |              |   |              |   |              |  
|Earnings from operations before the following:    | 18,866,852   |   | 23,276,789   |   | 10,952,911   |  
|Amortization and depletion [note 3]               | 24,182,205   |   | 12,021,474   |   | 6,322,863    |  
|Exploration expenses                              | 14,401,131   |   | 4,065,885    |   | 1,446,178    |  
|Gain on sale of natural gas and oil interests     | —            |   | —            |   | (2,139       | )
|(Loss) earnings before taxes                      | (19,716,484  | ) | 7,189,430    |   | 3,186,009    |  
|Income tax expense (recovery) [note 7]            |              |   |              |   |              |  
|- Current                                         | (51,730      | ) | 632,294      |   | 207,000      |  
|- Future                                          | (7,384,145   | ) | 1,578,834    |   | 974,703      |  
|Net (loss) earnings                               | (12,280,609  | ) | 4,978,302    |   | 2,004,306    |  
|                                                  |              |   |              |   |              |  
|Earnings (deficit), beginning of period           | 2,825,311    |   | (2,152,991   | ) | (4,025,241   | )
|Premium on purchase and cancellation of           |              |   |              |   |              |  
|common shares                                     | —            |   | —            |   | (132,056     | )
|(Deficit) retained earnings, end of period        | (9,455,298   | ) | 2,825,311    |   | (2,152,991   | )
|                                                  |              |   |              |   |              |  
|Net (loss) earnings per share [note 8]            |              |   |              |   |              |  
|basic                                             | (0.52        | ) | 0.23         |   | 0.10         |  
|diluted                                           | (0.52        | ) | 0.23         |   | 0.10         |  

See accompanying notes

F-3

---

Dynamic Oil & Gas, Inc.

STATEMENTS OF CASH FLOWS(in Canadian dollars)

|                                                  |              |   |              |   | Nine Months  |  
|------------------------------------------------- | ------------ | - | ------------ | - | ------------ | -
|                                                  | Year Ended   |   | Year Ended   |   | Ended        |  
|                                                  | December 31, |   | December 31, |   | December 31, |  
|                                                  | 2004         |   | 2003         |   | 2002         |  
|                                                  | $            |   | $            |   | $            |  
|                                                  |              |   |              |   |              |  
|OPERATING ACTIVITIES                              |              |   |              |   |              |  
|Net (loss) earnings                               | (12,280,609  | ) | 4,978,302    |   | 2,004,306    |  
|Add (deduct) items not involving cash:            |              |   |              |   |              |  
|Accretion of asset
      retirement obligation    | 102,836      |   | 93,843       |   | 63,876       |  
|Amortization and depletion                        | 24,182,205   |   | 12,021,474   |   | 6,322,863    |  
|Stock based compensation                          | 399,460      |   | 358,229      |   | —            |  
|Future income tax (recovery)
      expense        | (7,384,145   | ) | 1,578,834    |   | 974,703      |  
|Exploration expenses                              | 14,401,131   |   | 4,065,885    |   | 1,446,178    |  
|Gain on sale of natural gas and oil interests     | —            |   | —            |   | (2,139       | )
|                                                  | 19,420,878   |   | 23,096,567   |   | 10,809,787   |  
|Changes in non-cash working capital affecting     |              |   |              |   |              |  
|operating activities [note 9[a]]                  | (4,309,893   | ) | 5,197,611    |   | 646,829      |  
|Cash provided by operating activities             | 15,110,985   |   | 28,294,178   |   | 11,456,616   |  
|                                                  |              |   |              |   |              |  
|FINANCING ACTIVITIES                              |              |   |              |   |              |  
|Bank indebtedness                                 | (303,238     | ) | (133,685     | ) | 677,111      |  
|Operating loan                                    | 2,300,000    |   | 2,175,000    |   | (3,675,000   | )
|Shares issued for cash                            | 11,789,211   |   | 1,510,858    |   | —            |  
|Share repurchases                                 | —            |   | —            |   | (325,948     | )
|Cash provided by (used in) financing activities   | 13,785,973   |   | 3,552,173    |   | (3,323,837   | )
|                                                  |              |   |              |   |              |  
|INVESTING ACTIVITIES                              |              |   |              |   |              |  
|Purchase of capital assets                        | (225,087     | ) | (308,387     | ) | (84,420      | )
|Natural gas and oil interests                     | (22,774,931  | ) | (22,727,557  | ) | (12,493,116  | )
|Exploration expenses                              | (14,401,131  | ) | (4,065,885   | ) | (1,446,178   | )
|Settlement of asset retirement obligations        | (9,057       | ) | —            |   | —            |  
|Proceeds on sale of natural gas and oil interests | —            |   | —            |   | 2,139        |  
|Changes in non-cash working capital affecting     |              |   |              |   |              |  
|investing activities [note 9[b]]                  | 8,513,248    |   | (4,744,522   | ) | 5,888,796    |  
|Cash used in investing activities                 | (28,896,958  | ) | (31,846,351  | ) | (8,132,779   | )
|                                                  |              |   |              |   |              |  
|Decrease in cash and cash equivalents             | —            |   | —            |   | —            |  
|Cash and cash equivalents, beginning of period    | —            |   | —            |   | —            |  
|Cash and cash equivalents, end of period          | —            |   | —            |   | —            |  
|                                                  |              |   |              |   |              |  
|Supplemental disclosures of cash flow information |              |   |              |   |              |  
|Cash paid (received) during the year for:         |              |   |              |   |              |  
|Interest                                          | 595,903      |   | 555,536      |   | 459,237      |  
|Income taxes                                      | 1,148,276    |   | (150,408     | ) | 760,132      |  

See accompanying notes

F-4

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

1. DESCRIPTION OF BUSINESS

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting principles

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

Change in fiscal year end

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

Results of operations and cash flows

|                                                 | December 31, |   | December 31, |   | December 31, |  
|------------------------------------------------ | ------------ | - | ------------ | - | ------------ | -
|                                                 | 2004         |   | 2003         |   | 2002         |  
|Twelve months ended                              | $            |   | $            |   | $            |  
|                                                 |              |   |              |   |              |  
|Natural gas, liquids and oil sales               | 40,805,507   |   | 46,847,927   |   | 30,730,477   |  
|Net (loss) earnings                              | (12,280,609  | ) | 4,978,302    |   | 2,004,306    |  
|Net (loss) earnings per share                    |              |   |              |   |              |  
|basic                                            | (0.52        | ) | 0.23         |   | 0.02         |  
|diluted                                          | (0.52        | ) | 0.23         |   | 0.02         |  
|Cash flows                                       |              |   |              |   |              |  
|provided by operating
      activities           | 15,110,985   |   | 28,294,178   |   | 15,215,456   |  
|provided by (used in)
      financing activities | 13,785,973   |   | 3,552,173    |   | (4,331,528   | )
|used in investing activities                     | (28,896,958  | ) | (31,846,351  | ) | (10,900,821  | )

F-5

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

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

Use of estimates

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

Natural gas and oil interests

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

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

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

Joint interests

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

F-6

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

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

Capital assets

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

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

Income taxes

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

Asset retirement obligations

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

Revenue recognition

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

F-7

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

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

Stock-based compensation

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

Foreign currency translation

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

Measurement uncertainty

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

Earnings per share

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

F-8

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

3. NATURAL GAS AND OIL INTERESTS, AND CAPITAL
  ASSETS

|                                           |             | Accumulated      |           
|------------------------------------------ | ----------- | ---------------- | ----------
|                                           |             | Amortization and | Net Book  
|                                           | Cost        | Depletion        | Value     
|                                           | $           | $                | $         
|                                           |             |                  |           
|December 31, 2004                          |             |                  |           
|Natural gas and oil interests              | 116,246,542 | 59,520,048       | 56,726,494
|Furniture, fixtures and computer equipment | 709,089     | 294,176          | 414,913   
|                                           |             |                  |           
|December 31, 2003                          |             |                  |           
|Natural gas and oil interests              | 94,425,822  | 37,342,033       | 57,083,789
|Furniture, fixtures and computer equipment | 770,910     | 405,349          | 365,561   

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

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

4. OPERATING LOAN

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

F-9

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

5. ASSET RETIREMENT OBLIGATION

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

|                                                 | December 31, | December 31, | December 31,
|------------------------------------------------ | ------------ | ------------ | ------------
|                                                 | 2004         | 2003         | 2002        
|                                                 | $            | $            | $           
|                                                 |              |              |             
|Asset retirement obligation, beginning of period | 1,587,733    | 1,087,223    | 956,559     
|Liabilities incurred                             | 865,187      | 406,667      | 66,788      
|Accretion expense                                | 102,836      | 93,843       | 63,876      
|Asset retirement obligation, end of period       | 2,555,756    | 1,587,733    | 1,087,223   

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

F-10

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL

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

[a] Issued and outstanding

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

|                                   | December 31, |  | December 31, |  | December 31, | 
|---------------------------------- | ------------ |  | ------------ |  | ------------ | 
|                                   | 2004         |  | 2003         |  | 2002         | 
|                                   | Number       |  |              |  | Number       | 
|                                   | of           |  |              |  | of           | 
|                                   | shares       |  |              |  | shares       | 
|                                   | #            |  | $            |  | #            | 
|                                   |              |  |              |  |              | 
|Balance at beginning               |              |  |              |  |              | 
|of period                          | 22,194,778   |  | 27,747,487   |  | 20,272,530   | 
|Stock options exercised            | 84,200       |  | 167,450      |  | 871,582      | 
|Shares issued on flow-through      |              |  |              |  |              | 
|private placement                  | 2,000,000    |  | 10,752,216   |  | —            | 
|Shares issued on private           |              |  |              |  |              | 
|placements                         | 280,000      |  | 1,185,215    |  | —            | 
|Shares issued to repurchase gross  |              |  |              |  |              | 
|overriding royalty
      interests |              |  |              |  |              | 
|[note 6[d]]                        | —            |  | —            |  | 1,050,666    | 
|Share repurchases and              |              |  |              |  |              | 
|cancellations                      | —            |  | —            |  | —            | 
|Balance at period end              | 24,558,978   |  | 39,852,368   |  | 22,194,778   | 

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

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

F-11

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Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

[b] Stock option plan and options outstanding

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

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

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

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

|                          | December 31, 2004 |   | December 31, 2003 |  | December 31, 2002
|------------------------- | ----------------- | - | ----------------- |  | -----------------
|                          | Number of         |   | Weighted          |  | Number of        
|                          | Shares            |   | Average           |  | Shares           
|                          | Under Option      |   | Exercise Price    |  | Under Option     
|                          | #                 |   | $                 |  | #                
|                          |                   |   |                   |  |                  
|Outstanding at beginning  |                   |   |                   |  |                  
|of period                 | 1,615,834         |   | 2.61              |  | 2,077,750        
|Granted                   | 285,000           |   | 4.03              |  | 421,000          
|Exercised                 | (84,200           | ) | 1.99              |  | (871,582         
|Forfeited                 | (48,334           | ) | 3.00              |  | (11,334          
|Outstanding at period end | 1,768,300         |   | 2.86              |  | 1,615,834        
|Options exercisable at    |                   |   |                   |  |                  
|period end                | 1,371,300         |   | 2.64              |  | 1,081,667        

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

F-12

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Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

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

|            | Options Outstanding |                  | Options
      Exercisable
|----------- | ------------------- | ---------------- | -------------------------
|            |                     | Weighted Average |                          
|            | Number of           | Weighted         | Remaining                
|Exercise    | Shares Under        | Average          | Contractual              
|Price       | Option              | Exercise Price   | Life                     
|$           | #                   | $                | (Years)                  
|            |                     |                  |                          
|1.00 - 1.49 | 35,000              | 1.45             | 0.06                     
|1.50 - 1.99 | 555,000             | 1.73             | 3.86                     
|2.00 - 2.49 | 480,300             | 2.12             | 2.34                     
|2.50 - 2.99 | 15,000              | 2.95             | 7.96                     
|3.50 - 3.99 | 187,500             | 3.70             | 4.70                     
|4.00 - 4.49 | 140,000             | 4.11             | 6.30                     
|4.50 - 4.99 | 280,500             | 4.68             | 3.72                     
|5.00 - 5.49 | 75,000              | 5.35             | 3.54                     
|            | 1,768,300           | 2.86             | 3.65                     

[c] Accounting for stock options

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

F-13

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

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

|                                              |              |   |             | Nine Months 
|--------------------------------------------- | ------------ | - | ----------- | ------------
|                                              | Year Ended   |   | Year Ended  | Ended       
|                                              | December 31, |   | December 31 | December 31,
|                                              | 2004         |   | 2003        | 2002        
|                                              | $            |   | $           | $           
|                                              |              |   |             |             
|Net (loss) earnings:                          |              |   |             |             
|as reported                                   | (12,280,609  | ) | 4,978,302   | 2,004,306   
|pro forma                                     | (12,381,302  | ) | 4,856,567   | 1,798,630   
|Basic net (loss) earnings per common share:   |              |   |             |             
|as reported                                   | (0.52        | ) | 0.23        | 0.10        
|pro forma                                     | (0.52        | ) | 0.23        | 0.09        
|Diluted net (loss) earnings per common share: |              |   |             |             
|as reported                                   | (0.52        | ) | 0.23        | 0.10        
|pro forma                                     | (0.52        | ) | 0.22        | 0.09        

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

|                        |              |             | Nine Months 
|----------------------- | ------------ | ----------- | ------------
|                        | Year Ended   | Year Ended  | Ended       
|                        | December 31, | December 31 | December 31,
|                        | 2004         | 2003        | 2002        
|                        | $            | $           | $           
|                        |              |             |             
|Dividend yield          | 0%           | 0%          | 0%          
|Expected volatility     | 47%          | 51%         | 57%         
|Risk-free interest rate | 4.25%        | 4.00%       | 5.00%       
|Expected lives          | 3 years      | 3 years     | 3 years     

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

F-14

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

6. SHARE CAPITAL (cont’d.)

[d] Repurchase of gross overriding royalty interests

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

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

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

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

F-15

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

7. INCOME TAXES

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

|                                               | December 31, | December 31, |  
|---------------------------------------------- | ------------ | ------------ | -
|                                               | 2004         | 2003         |  
|                                               | $            | $            |  
|                                               |              |              |  
|Long term future tax assets (liabilities):     |              |              |  
|Tax basis of oil and
      gas interests       |              |              |  
|and fixed assets greater
      than book basis | 1,397,107    | (5,843,546   | )
|Finance charges                                | 247,126      | 100          |  
|Asset retirement obligation                    | 437,359      | 225,723      |  
|Net future tax assets (liabilities)            | 2,082,092    | (5,617,723   | )

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

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

|                                          |                   |   |                   |  |                   |   |       |  | Nine Months
|----------------------------------------- | ----------------- | - | ----------------- |  | ----------------- | - | ----- |  | -----------
|                                          | Year Ended        |   | Year Ended        |  | Ended            
|                                          | December 31, 2004 |   | December 31, 2003 |  | December 31, 2002
|                                          | $                 |   | %                 |  | $                 |   | %     |  | $          
|                                          |                   |   |                   |  |                   |   |       |  |            
|Tax at combined federal and               |                   |   |                   |  |                   |   |       |  |            
|provincial rates                          | (7,870,820        | ) | 39.92             |  | 2,962,000         |   | 41.20 |  | 1,350,000  
|Tax effect of:                            |                   |   |                   |  |                   |   |       |  |            
|Non-deductible expenses                   | 1,198,057         |   |                   |  | 1,929,000         |   |       |  | 898,400    
|Income not taxable                        | (43,080           | ) |                   |  | (165,400          | ) |       |  | (70,500    
|Resource allowance                        | (1,343,458        | ) |                   |  | (2,218,342        | ) |       |  | (1,021,197 
|Large corporation tax in excess of surtax | —                 |   |                   |  | 90,000            |   |       |  | 25,000     
|Effect of changes in tax rates            | 700,429           |   |                   |  | (386,130          | ) |       |  | —          
|Other                                     | (77,003           | ) |                   |  | —                 |   |       |  | —          
|                                          | (7,435,875        | ) |                   |  | 2,211,128         |   |       |  | 1,181,703  

F-16

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

8. NET (LOSS) EARNINGS PER SHARE

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

|                                      | Year Ended   |   | Year Ended   |  | Nine Months Ended
|------------------------------------- | ------------ | - | ------------ |  | -----------------
|                                      | December 31, |   | December 31, |  | December 31,     
|                                      | 2004         |   | 2003         |  | 2002             
|                                      | $            |   | $            |  | $                
|                                      |              |   |              |  |                  
|Numerator                             |              |   |              |  |                  
|Net (loss) earnings for the period    | (12,280,609  | ) | 4,978,302    |  | 2,004,306        
|                                      |              |   |              |  |                  
|Denominator                           |              |   |              |  |                  
|Weighted average number of common     |              |   |              |  |                  
|shares outstanding                    | 23,665,110   |   | 21,393,902   |  | 20,357,153       
|Effect of dilutive stock options      | —            |   | 553,899      |  | 197,078          
|                                      | 23,665,110   |   | 21,947,801   |  | 20,554,231       
|                                      |              |   |              |  |                  
|Basic net (loss) earnings per share   | (0.52        | ) | 0.23         |  | 0.10             
|Diluted net (loss) earnings per share | (0.52        | ) | 0.23         |  | 0.10             

F-17

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

9. CHANGES IN NON-CASH WORKING CAPITAL BALANCES

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

|[b] | Changes affecting investing activities comprise: |              |   |              |   |                   | 
|--- | ------------------------------------------------ | ------------ | - | ------------ | - | ----------------- | 
|    |                                                  |              |   |              |   |                   | 
|    |                                                  | Year Ended   |   | Year Ended   |   | Nine Months Ended | 
|    |                                                  | December 31, |   | December 31, |   | December 31,      | 
|    |                                                  | 2004         |   | 2003         |   | 2002              | 
|    |                                                  | $            |   | $            |   | $                 | 
|    | Accounts receivable                              | (212,934     | ) | (1,834,645   | ) | 521,453           | 
|    | Accounts payable and accrued liabilities         | 8,726,182    |   | (2,909,877   | ) | 5,367,343         | 
|    |                                                  | 8,513,248    |   | (4,744,522   | ) | 5,888,796         | 

10. FINANCIAL INSTRUMENTS

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

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

F-18

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

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

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

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

|                                                      | Year Ended   |   | Year Ended   |   | Nine Months Ended |  
|----------------------------------------------------- | ------------ | - | ------------ | - | ----------------- | -
|                                                      | December 31, |   | December 31, |   | December 31,      |  
|                                                      | 2004         |   | 2003         |   | 2002              |  
|                                                      | $            |   | $            |   | $                 |  
|                                                      |              |   |              |   |                   |  
|Net (loss) earnings under Canadian GAAP               | (12,280,609  | ) | 4,978,302    |   | 2,004,306         |  
|Amortization and depletion [a]                        | —            |   | —            |   | (65,471           | )
|Accretion of asset retirement obligation [a]          | —            |   | —            |   | 40,242            |  
|Options issued for services [b]                       | —            |   | —            |   | (3,108            | )
|Write-down on natural gas and oil                     |              |   |              |   |                   |  
|properties [c]                                        | —            |   | (125,580     | ) | (209,160          | )
|Net (loss) earnings before cumulative                 |              |   |              |   |                   |  
|effect of change in
      accounting principle        |              |   |              |   |                   |  
|under U.S. GAAP                                       | (12,280,609  | ) | 4,852,722    |   | 1,766,809         |  
|                                                      |              |   |              |   |                   |  
|Cumulative effect of change in accounting             |              |   |              |   |                   |  
|principle, net of applicable taxes
      [a]          | —            |   | 133,276      |   | —                 |  
|                                                      |              |   |              |   |                   |  
|Net (loss) earnings under U.S. GAAP after             |              |   |              |   |                   |  
|cumulative effect of
      change in accounting       |              |   |              |   |                   |  
|principle                                             | (12,280,609  | ) | 4,985,998    |   | 1,766,809         |  
|                                                      |              |   |              |   |                   |  
|Net (loss) earnings per common share under U.S. GAAP, |              |   |              |   |                   |  
|before change in accounting
      policy              |              |   |              |   |                   |  
|- basic                                               | (0.52        | ) | 0.23         |   | 0.09              |  
|- diluted                                             | (0.52        | ) | 0.22         |   | 0.09              |  
|                                                      |              |   |              |   |                   |  
|Net (loss) earnings per common share under U.S. GAAP, |              |   |              |   |                   |  
|after change in accounting
      policy               |              |   |              |   |                   |  
|- basic                                               | (0.52        | ) | 0.23         |   | 0.09              |  
|- diluted                                             | (0.52        | ) | 0.23         |   | 0.09              |  

F-19

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

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

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

|                                      | December 31 |   | December 31 |  
|------------------------------------- | ----------- | - | ----------- | -
|                                      | 2004        |   | 2003        |  
|                                      | Canadian    |   | U.S.        |  
|                                      | GAAP        |   | GAAP        |  
|                                      | $           |   | $           |  
|                                      |             |   |             |  
|Natural gas and oil interests [c]     | 56,726,494  |   | 56,726,494  |  
|Share capital [b, d]                  | 39,852,368  |   | 38,725,461  |  
|Accounts payable and                  |             |   |             |  
|accrued liabilities
      [d]         | 17,348,723  |   | 19,448,723  |  
|(Deficit) retained earnings [a, b, c] | (9,455,298  | ) | (10,949,459 | )

|[a] | Asset retirement obligation                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|    | During 2003, the Company early-adopted CICA Handbook
        section 3110 - “Asset Retirement Obligations” for Canadian
        GAAP and SFAS 143 - “Accounting for Asset Retirement Obligations”
        for U.S. GAAP. The transitional provisions differ between Canadian GAAP
        and U.S. GAAP in that Canadian GAAP requires restatement of comparative
        amounts whereas U.S. GAAP does not allow restatement, but rather requires
        a cumulative catch-up adjustment to earnings. An adjustment to net earnings
        under Canadian GAAP has been recorded to reflect the December 31, 2002
        comparative amounts prior to restatement in accordance with U.S. GAAP.                                                                
|   
|[b] | Stock-based compensation                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|   
|    | In December 2004, FASB issued SFAS No. 123 (Revised),
        “Share-Based Payments”. This statement requires an entity
        to recognize the grant-date fair value of stock options and other equity-based
        compensation issued to employees in the statement of operations. SFAS
        123 (Revised) eliminates the ability to account for share-based compensation
        transactions using the intrinsic value method in APB Opinion 25. The Company,
        effective January 1, 2003, early adopted FASB Statement No. 123, “Accounting
        for Stock-Based Compensation - Transition and Disclosure”. Accordingly,
        these revisions to SFAS No. 123 did not have a significant impact on the
        Company’s financial statements.

F-20

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

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

|[c] | Under both U.S. and Canadian GAAP, property, plant
        and equipment must be assessed for potential impairments. Under U.S. GAAP,
        if the sum of the expected future cash flows (undiscounted and without
        interest charges) is less than the carrying amount of the asset, then
        an impairment loss (the amount by which the carrying amount of the asset
        exceeds the fair value of the asset) should be recognized. Fair value
        is calculated as the present value of estimated expected future cash flows.
        Prior to 2004, under Canadian GAAP, the impairment loss was recognized
        as the difference between the carrying value of the asset and its net
        recoverable amount (undiscounted). The Company has adopted a new standard
        effective for 2004 that has eliminated this U.S./Canadian GAAP difference.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|[d] | For U.S. GAAP, the premium received by the Company
        on the issuance of flow-through shares which is in excess of the fair
        value of common shares is required to be credited to liabilities. The
        liability is reversed when tax benefits are renounced and a deferred tax
        liability is recognized in respect of renounced Canadian exploration expenses
        at that time. Any difference arising between the liability and deferred
        tax liability is accounted for as an income tax expense. During 2004,
        total flow-through share premium received was $2,100,000.                                                                                                                                                                                                                                                                  
|   
|[e] | For U.S. GAAP, dry hole expenses of $10,166,601
        for the year ended December 31, 2004 [year ended December 31, 2003 - $1,278,387;
        nine-month period ended December 31, 2002 - $325,478] included in
        investing activities on the statement of cash flows would be reported
        in operating activities. Under U.S. GAAP, separate subtotals within cash
        flow from operating activities are not presented.                                                                                                                                                                                                                                                                                                                                                                                                                                            

12. COMMITMENTS

|[a] | The Company has entered into an operating lease
        in respect of its office premises.                   
|--- | -------------------------------------------------------------------------------------------------------------
|   
|    | The minimum payments under this lease commitment,
        including estimated operating costs are as follows:

| |      | $      
| | ---- | -------
| |      |        
| | 2005 | 203,657
| | 2006 | 203,657
| | 2007 | 203,657
| | 2008 | 84,857 
| |      | 695,828

F-21

---

Dynamic Oil & Gas, Inc.

NOTES TO FINANCIAL STATEMENTS(in Canadian dollars)

December 31, 2004

12. COMMITMENTS (cont’d.)

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

13. ECONOMIC DEPENDENCY

|[a] | The St. Albert property in Alberta is a core property
        of the Company and the majority of gas production from the property is
        pipelined and processed through facilities owned and operated by Atco
        Midstream (“Atco”) of Calgary, Alberta.                                                                                                                                                                                                                           
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|    | Effective November 1, 1997, the Company and its
        then joint interest partner, Fletcher Challenge Energy Canada Inc. signed
        a ten-year, firm service, sour gas processing and transportation agreement
        with Atco for a maximum daily quantity of 15 million cubic feet of gas
        per day to be processed at Atco’s Carbondale plant.                                                                                                                              
|   
|    | Effective December 15, 1998, a similar agreement
        was signed by the partners and Atco to process sweet gas at Atco’s
        Villenueve plant, also for a maximum daily quantity of 15 million cubic
        feet of gas per day.                                                                                                                                                                                                                                                     
|   
|    | Both agreements include an automatic renewal for
        a further ten years, subject to fee renegotiation.                                                                                                                                                                                                                                                                                                                                                                                  
|   
|[b] | During the year ended December 31, 2004, three customers
        accounted for 85% of the Company’s sales with totals of 45%, 30%
        and 10% respectively [year ended December 31, 2003 – three customers
        accounted for 82% of the Company’s sales with totals of 37%, 30%
        and 15% respectively; nine-month period ended December 31, 2002 –
        four customers accounted for 92% of the Company’s sales with totals
        of 35%, 33%, 13% and 11% respectively].

14. SUBSEQUENT EVENTS

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

F-22

---



INDEX TO EXHIBITS

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

88

---

---



INDEX TO EXHIBITS continued

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

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

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

89

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---