Document:

Filed by Automated Filing Services Inc. (604) 609-0244 - Shellbridge Oil & Gas, Inc. - Exhibit 4.8

 

 

REPORT ON RESERVES DATA AND
OTHER

OIL AND GAS
INFORMATION

NI 51-101

TABLE OF CONTENTS

	  	  	Pages 
	 	 	 
	Glossary
      of Terms 	3
      
	Form 51-101F1 	  
	Item
      2.1 	Reserves
      Data - Constant Prices and Costs 	5
      
	Item
      2.2 	Reserves
      Data - Forecast Prices and Costs 	6
      
	Item
      2.3 	Reserves
      Disclosure Varies with Accounting 	7
      
	Item
      2.4 	Future
      Net Reserves Disclosure Varies with Accounting 	7
      
	Item
      3.1 	Constant
      Prices Used in Estimates 	7
      
	Item
      3.2 	Forecast
      Prices Used in Estimates 	8
      
	Item
      4.1 	Reserves
      Reconciliation 	9
      
	Item
      4.2 	Future
      Net Revenue Reconciliation 	9
      
	Item
      5.1 	Undeveloped
      Reserves 	9
      
	Item 5.2 	Significant Factors and Uncertainties 	9-10 
	Item
      5.3 	Future
      Development Costs 	10
      
	Item 6.1 	Oil and Gas Properties and Wells 	11-14 
	Item 6.2 	Undeveloped Properties Having No Attributed Reserves
      	14-15 
	Item
      6.3 	Forward
      Contracts 	15
      
	Item
      6.4 	Additional
      Information - Abandonment and Reclamation Costs 	16
      
	Item
      6.5 	Tax
      Horizon 	16
      
	Item
      6.6 	Costs
      Incurred 	16
      
	Item
      6.7 	Exploration
      and Development Activities 	16
      
	Item
      6.8 	Production
      Estimates 	17
      
	Item 6.9 	Production History 	17-18 
	Form 51-101F2 	19-20 
	Form 51-101F3 	21-22 

2

 

	Glossary
      of Terms
	Reserves	Estimated reserves of natural gas, natural gas liquids
        and crude oil.

	Working interest	Those lands in which the Company receives its share
        acreage of net production revenues.

	Gross reserves	Estimated reserves before royalties based on working
        interest.

	Net reserves	Estimated reserves after royalties based on working
        interest

	Future net revenue	Working interest revenues after royalties, development
        costs, production costs and well abandonment costs, but before administrative,
        overhead and other such indirect costs. Future net revenue may be presented
        either before or after tax.

	Proved reserves	Reserves that can be estimated with a high degree
        of certainty to be recoverable. It is likely that the actual remaining
        quantities recovered will exceed the estimated proved reserves.

	Probable reserves	Reserves that are less certain than proved reserves
        at being recovered. It is equally likely that the actual remaining quantities
        recovered will be greater or less than the sum of the estimated proved
        plus probable reserves

	Developed reserves	Reserves that are expected to be recovered from existing
        wells and installed facilities or, if facilities have not been installed,
        that would involve a low expenditure (e.g. when compared to the cost of
        drilling a well) to put the reserves on production.

	Developed producing reserves	Reserves that are expected to be recovered from completion
        intervals open at the time of estimate. These reserves may be currently
        producing or, if shut-in, they must have previously been on production,
        and the date of resumption of production must be known with reasonable
        certainty.

	Developed non-producing reserves	Reserves that either have not been on production,
        or have previously been on production, but are shut in, and the date of
        resumption of production is unknown.

	stb or stock tank barrel	A 42-gallon barrel of crude oil at standard conditions
        of temperature and pressure.

	mbbl	1,000 barrels of oil and/or natural gas liquids.

	MMBtu	A unit of heat equal to one million British thermal
        units. 

	mcf	1,000 cubic feet of natural gas.

	bbl or barrel	42 U.S. gallons liquid volume of crude oil or natural
        gas liquids.

	Undeveloped reserves	Reserves that are expected to be recovered from known
        accumulation where a significant expenditure is required to render them
        capable of production (e.g. in comparison to the cost of drilling a well).
        Such reserves must fully meet the requirements of the reserves classification
        to which they are assigned (proved or probable).

3

Form 51-101F1

STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION
FOR SHELLBRIDGE OIL & GAS, INC.

This is the form referred to in item 1 of section 2.1 of
National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities (“NI 51-101”). 

We commenced operations on October 1, 2005, when certain
assets of Dynamic Oil & Gas, Inc. (“Dynamic”) were transferred to us upon
the completion of a Plan of Arrangement. The Plan of Arrangement resulted in,
amongst other things, the shareholders of Dynamic obtaining cash and voting
common shares in our capital.

The information in this report is as at December 31, 2005
and is the first disclosure of our reserves since the effective date of the Plan
of Arrangement (September 30, 2005). As a result, there is no historical
reserves information of a comparative or reconciling nature.

The following information is related to our reserves, future
net revenue and discounted value of future net cash flow of natural gas, natural
gas liquids, light/medium crude oil and heavy crude oil. Sproule Associates
Limited (“Sproule”), independent qualified evaluators of Calgary, Alberta
estimated these reserves effective December 31, 2005. We used these reserves in
the preparation of our Financial Statements for the fiscal year ended December
31, 2005. 

All our reserves are in Saskatchewan, Alberta and British
Columbia, Canada. 

The reserves on our properties described herein are estimates
only. Actual reserves on our properties may be greater or less than those
calculated.

The estimated future net revenue contained in the following
tables does not necessarily represent the fair market value of our reserves.
There is no assurance that forecast prices and costs assumed in the Sproule
evaluation will be attained, and variances could be material. Assumptions and
qualifications relating to costs and other matters are summarized in the notes
to the following tables. 

The following tables provide reserves data and a breakdown of
future net revenue by commodity and reserve category using forecast prices and
costs and/or constant prices and costs, based on our working interest portion
before royalties (gross) and/or after royalties (net) (see “Glossary of Terms”).

The pricing used in tables that reflect constant and forecast
price evaluations is set forth in Items 3.1 and 3.2, respectively.

4

Item 2.1 Reserves Data (Constant Prices and Costs)

	Item 2.1(1) 	The following table shows our gross and net
      reserves by reserve category using constant prices and costs.
  

  	Summary of Reserves 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	Based
        on Constant Prices and Costs 	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	  	 	Light and 	 	 	  	 	 	  	 	 	  	 	 	  	 	 	Natural Gas 	 
	  	 	Medium Oil 	 	 	Heavy Oil 	 	 	Natural Gas(1)		 	Liquids 	 
	  	 	Gross 	 	 	Net 	 	 	Gross 	 	 	Net 	 	 	Gross 	 	 	Net 	 	 	Gross 	 	 	Net 	 
	Reserve Category
      	 	(mbbl)
      	 	 	(mbbl)	 	 	(mbbl) 	 	 	(mbbl) 	 	 	(mmcf) 	 	 	(mmcf) 	 	 	(mbbl) 	 	 	(mbbl) 	 
	Proved 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	   Developed producing 	 	5 	 	 	5 	 	 	745 	 	 	593 	 	 	623 	 	 	460 	 	 	- 	 	 	- 	 
	   Developed non- 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	      producing 	 	- 	 	 	- 	 	 	66 	 	 	54 	 	 	377 	 	 	294 	 	 	6 	 	 	5 	 
	    Undeveloped 	 	- 	 	 	- 	 	 	260 	 	 	210 	 	 	562 	 	 	412 	 	 	- 	 	 	-` 	 
	Total proved 	 	5 	 	 	5 	 	 	1,071 	 	 	857 	 	 	1,562 	 	 	1,166 	 	 	6 	 	 	5 	 
	Probable 	 	2 	 	 	2 	 	 	1,118 	 	 	896 	 	 	904 	 	 	686 	 	 	7 	 	 	5 	 
	Total proved + probable
      	 	7 	 	 	7 	 	 	2,189
      	 	 	1,753
      	 	 	2,466
      	 	 	1,852
      	 	 	13 	 	 	10 	 

(1) Includes solution gas.

	Item 2.1(2) 	
      The following table shows the net present values of the
      future net revenue of our net reserves by reserve category using constant
      prices and costs. 

	Summary of Net Present Values of Future Net
      Revenue 	 	 	  	 	 	  	 
	Based on
      Constant Prices and Costs 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 
	($000’s) 	 	Before Income Taxes 	 	 	After Income Taxes 	 
	  	 	Annual Discount Rate 	 	 	Annual Discount Rate 	 
	Reserve Category 	 	0% 	 	 	10% 	 	 	0% 	 	 	10% 	 
	Proved 	 	  	 	 	  	 	 	  	 	 	  	 
	     Developed producing 	 	11,200 	 	 	9,865 	 	 	10,781 	 	 	9,431 	 
	     Developed non-producing 	 	2,823 	 	 	2,484 	 	 	2,071 	 	 	1,770 	 
	     Undeveloped 	 	4,122 	 	 	2,951 	 	 	3,332 	 	 	2,214 	 
	Total proved 	 	18,145 	 	 	15,300 	 	 	16,184 	 	 	13,416 	 
	Probable 	 	17,008 	 	 	12,110 	 	 	12,676 	 	 	8,475 	 
	Total proved plus
      probable 	 	35,153
    	 	 	27,410
    	 	 	28,860
    	 	 	21,891
    	 

	Item 2.1(3)(a) 
and
      (b) 	
      The following table shows the net present values of the
      future net revenue of our net reserves by reserve category using constant
      prices and costs, undiscounted. 

	Total Future Net Revenue –
      Undiscounted 	 	 		 	 	  	 	 	  	 	 	  	 	 	  	 
	Based
      on Constant Prices and Costs 	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 
	($000’s) 	 	  	 	 	  	 	 	  	 	 	  	 	 	Well 	 	 	Future Net 	 	 	  	 	 	  	 
	  	 	  	 	 	  	 	 	  	 	 	  	 	 	Abandonment 	 	 	Revenue 	 	 	  	 	 	Future Net 	 
	Reserve 	 	  	 	 	  	 	 	Operating 	 	 	Development 	 	 	and Other 	 	 	Before Income 	 	 	Income 	 	 	Revenue After 	 
	Category 	 	Revenue 	 	 	Royalties 	 	 	Costs 	 	 	Costs 	 	 	Costs 	 	 	Taxes 	 	 	Taxes 	 	 	Income Taxes 	 
	Proved 	 	48,201 	 	 	10,520 	 	 	14,262 	 	 	4,033 	 	 	1,241 	 	 	18,145 	 	 	1,961 	 	 	16,184 	 
	Proved plus 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	    probable 	 	91,601 	 	 	19,814 	 	 	25,509 	 	 	8,926 	 	 	2,199 	 	 	35,153 	 	 	6,293 	 	 	28,860 	 

	Item 2.1(3)(c) 	
      The following table shows the net present values of the
      future net revenue of our net reserves by reserve category using constant
      prices and costs before deducting future income tax expenses using a 10%
      discount rate.

5

	Future Net Revenue by Production Group 	  
	Based
      on Constant Prices and Costs 	 
    
	($000’s) 	  	Future Net Revenue Before Income 
	Reserves Category
    	Production Group 	Taxes – Discounted Annually @ 10% 
	Proved reserves 	Light and medium crude oil
      (1) 	82 
	  	Heavy oil (1) 	9,511 
	  	Natural gas (2) 	5,706 
	Proved plus probable 	Light and medium crude oil (1) 	99 
	  	Heavy oil (1) 	18,484 
	  	Natural gas (2) 	8,826 

	(1) 	
      Includes solution gas and associated
  by-products.

	(2) 	
      Includes associated by-products but excluding solution
      gas from oil wells.

Item 2.2 Reserves Data (Forecast Prices and Costs)

	Item 2.2(1) 	The following table shows our gross and net
      reserves by reserve category using forecast prices and costs.
  

	Summary of Reserves 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	Based
      on Forecast Prices and Costs 	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 
	  	 	Light and 	 	 	  	 	 	  	 	 	  	 	 	  	 	 	Natural Gas 	 
	  	 	Medium Oil 	 	 	Heavy Oil 	 	 	Natural Gas (1)		 	Liquids 	 
	  	 	Gross 	 	 	Net 	 	 	Gross 	 	 	Net 	 	 	Gross 	 	 	Net 	 	 	Gross 	 	 	Net 	 
	Reserve Category
    	 	(mbbl) 	 	 	(mbbl) 	 	 	(mbbl) 	 	 	(mbbl) 	 	 	(mmcf) 	 	 	(mmcf) 	 	 	(mbbl) 	 	 	(mbbl) 	 
	Proved 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	   Developed producing 	 	5 	 	 	5 	 	 	745 	 	 	591 	 	 	620 	 	 	457 	 	 	- 	 	 	- 	 
	   Developed non- 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	      producing 	 	- 	 	 	- 	 	 	66 	 	 	54 	 	 	377 	 	 	294 	 	 	6 	 	 	5 	 
	Undeveloped 	 	- 	 	 	- 	 	 	260 	 	 	209 	 	 	562 	 	 	412 	 	 	- 	 	 	- 	 
	Total proved 	 	5 	 	 	5 	 	 	1,071 	 	 	854 	 	 	1,559 	 	 	1,164 	 	 	6 	 	 	5 	 
	Probable 	 	2 	 	 	2 	 	 	1,118 	 	 	895 	 	 	891 	 	 	676 	 	 	7 	 	 	5 	 
	Total proved +
      probable 	 	7 	 	 	7 	 	 	2,189
    	 	 	1,749
    	 	 	2,450
    	 	 	1,840
    	 	 	13 	 	 	10 	 

	(1) 	
      Includes solution gas.

	Item 2.2(2) 	The following table shows the net present value
      of future net revenue for our net reserves by reserve category using
      forecast prices and costs. 

	Summary of Net Present Values of Future Net
      Revenue 	 	 	  	 	 	  	 	 	  	 	 	  	 
	Based
      on Forecast Prices and Costs 	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 
	($000’s) 	 	  	 	 	Before Income Taxes 	 	 	  	 	 	  	 	 	After Income Taxes 	 	 	  	 
	Reserve 	 	  	 	 	Annual Discount Rate 	 	 	  	 	 	  	 	 	Annual Discount Rate 	 	 	  	 
	Category 	 	0%
	 	 	5%
	 	 	10%
    	 	 	15%
    	 	 	20%
    	 	 	0%
	 	 	5%
	 	 	10%
    	 	 	15%
    	 	 	20%
    	 
	Proved 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	 Developed 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	   producing 	 	13,428 	 	 	12,669 	 	 	12,014 	 	 	11,442 	 	 	10,937 	 	 	12,280 	 	 	11,533 	 	 	10,892 	 	 	10,332 	 	 	9,840 	 
	 Developed 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	   non-producing 	 	3,169 	 	 	2,990 	 	 	2,831 	 	 	2,690 	 	 	2,563 	 	 	1,989 	 	 	1,854 	 	 	1,735 	 	 	1,630 	 	 	1,537 	 
	 
       Undeveloped 	 	4,466
    	 	 	3,887
    	 	 	3,408
    	 	 	3,005
    	 	 	2,663
    	 	 	3,333
    	 	 	2,800
    	 	 	2,363
    	 	 	2,001
    	 	 	1,696
    	 
	Total proved 	 	21,063 	 	 	19,546 	 	 	18,253 	 	 	17,137 	 	 	16,163 	 	 	17,602 	 	 	16,187 	 	 	14,990 	 	 	13,963 	 	 	13,073 	 
	  Probable
	 	18,028
    	 	 	15,382
    	 	 	13,319
    	 	 	11,671
    	 	 	10,330
    	 	 	13,027
    	 	 	10,794
    	 	 	9,087
    	 	 	7,751
    	 	 	6,682
    	 
	Total proved 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	   plus
      probable 	 	39,091
    	 	 	34,928
    	 	 	31,572
    	 	 	28,808
    	 	 	26,493
    	 	 	30,629
    	 	 	26,981
    	 	 	24,077
    	 	 	21,714
    	 	 	19,755
    	 

6

	Item 2.2(3)(a) 
and (b) 	
      The following table shows the future net revenue of our
      net reserve by reserves category using forecast prices and costs, and
      undiscounted. 

	Total Future Net Revenue – Undiscounted
    	 	 	  	 	 	  	 	 	  	 
	Based
      on Forecast Prices and Costs 	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 	 	 
    	 
	  	 	  	 	 	 	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	($000’s) 	 	  	 	 	 	 	 	  	 	 	  	 	 	Well 	 	 	Future Net 	 	 	  	 	 	  	 
	  	 	  	 	 	 	 	 	  	 	 	  	 	 	Abandonment 	 	 	Revenue 	 	 	  	 	 	Future Net 	 
	Reserve 	 	  	 	 	 	 	 	Operating  	 	 	Development 	 	 	and Other 	 	 	Before Income 	 	 	Income 	 	 	Revenue After 	 
	Category 	 	Revenue 	 	 	Royalties 	 	 	Costs 	 	 	Costs 	 	 	Costs 	 	 	Taxes 	 	 	Taxes 	 	 	Income Taxes 	 
	Proved 	 	53,626 	 	 	12,233	 	 	14,896 	 	 	4,035 	 	 	1,399 	 	 	21,063 	 	 	3,461 	 	 	17,602 	 
	Proved 	 	  	 	 	 	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	  plus 	 	  	 	 	 	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	  probable
	 	100,045 	 	 	22,448	 	 	27,030
    	 	 	8,996
    	 	 	2,480
    	 	 	39,091
    	 	 	8,462
    	 	 	30,629
    	 

	Item 2.2(3)(c) 	
      The following table shows the net present value of future
      net revenue of our net reserves by reserve category using forecast prices
      and costs before deducting future income tax expense, discounted at 10%.
      

	Future Net Revenue by Production Group 	  
	Based
      on Forecast Prices and Costs 	 
    
	($000’s) 	  	Future Net Revenue Before Income 
	Reserves Category
    	Production Group 	Taxes – Discounted Annually @ 10% 
	Proved reserves 	Light and medium crude oil
      (1) 	81 
	  	Heavy oil (1) 	12,358 
	  	Natural gas (2) 	5,814 
	Proved plus probable 	Light and medium crude oil (1) 	98 
	  	Heavy oil (1) 	23,037 
	  	Natural gas (2) 	8,436 

	(1) 	
      Includes solution gas and associated
  by-products.

	(2) 	
      Includes associated by-products but excluding solution
      gas from oil wells.

	Item 2.3	Reserves Disclosure Varies with Accounting 
	 	 
	  	We have no subsidiary interests. 
	 	 
	Item 2.4	Future Net Reserves Disclosure Varies with Accounting
    
	 	 
	  	We have no subsidiary interests. 
	 	 
	Item 3.1 	Constant Prices Used in Estimates 
	 	 
	  	The following table shows benchmark reference prices that have
      been used by Sproule in evaluating our reserves. 

7

	 Summary of Pricing Assumptions 	  	  	  
	 Based on Constant Prices and Costs 	 
    	 
    	 
    
	  	  	Crude Oil 	Natural Gas 	  
	  	  	WTI 	 Hardisty 	Cromer 	Natural Gas (1) 	Butanes 	  
	Year 	  	Cushing 	Heavy 	Medium 	AECO Gas 	FOB Field 	Exchange 
	  	  	Oklahoma 	 12o API 	29.3o API 	Prices 	Gate 	Rate (2) 
	Historical 	  	($US/bbl) 	 ($Cdn/bbl) 	($Cdn/bbl)  	 ($Cdn/MMBtu) 	($Cdn/bbl) 	($US/$Cdn) 
	Dec. 31, 	2000 	26.83 	6.11 	32.58 	13.34 	46.69 	0.667 
	Dec. 31, 	2001 	19.78 	 15.47 	22.41 	3.64 	16.73 	0.628 
	Dec. 31, 	2002 	31.23 	 16.20 	41.95 	5.97 	38.91 	0.634 
	Dec. 31, 	2003 	32.56 	 23.32 	36.39 	6.88 	37.73 	0.771 
	Dec. 31, 	2004 	44.04 	 15.26 	32.10 	6.78 	39.78 	0.832 
	Forecast 	  	  	  	  	  	  	  
	Dec. 31, 	2005 	61.04 	 30.86 	52.28 	9.99 	59.32 	0.860 

  

  	(1)	This summary table identifies benchmark reference pricing schedules
        that might apply to a reporting issuer. 
	(2)	Exchange rates used to generate the benchmark reference prices in this
        table.

 Notes: Product sale prices will reflect these reference prices
  with further adjustments for quality and transportation to point of sale. 

	Item 3.2 	Forecast Prices Used in Estimates

      The following table shows historical and future pricing
        and inflation rate assumptions used by Sproule in evaluating our reserves.

	Summary of Pricing and Inflation Rate
      Assumptions 	  	  	  
	Based
      on Forecast Prices and Costs 	 
    	 
    	 
    	 
    	 
    
	  	Crude Oil 	Natural Gas 	Natural Gas Liquids 	  	  
	  	WTI 	Edmonton 	Cromer 	Natural Gas (1)  	Pentanes 	Butanes 	  	  
	Year 	Cushing 	Par Price 	Medium 	AECO Gas 	plus FOB 	FOB Field 	Inflation 	Exchange  
	  	Oklahoma 	 40o API 	29.3o API 	Prices 	Field Gate 	Gate 	Rates 	Rate (3) 
	Historical 	($US/bbl) 	 ($Cdn/bbl) 	 ($Cdn/bbl) 	 ($Cdn/MMBtu) 	 ($Cdn/bbl) 	($Cdn/bbl) 	%/Yr
      (2) 	($US/$Cdn)  
	2001 	25.94 	 39.06 	31.56 	6.23 	42.46 	27.93 	 2.0 	0.646 
	2002 	26.09 	 40.12 	35.46 	4.04 	40.80 	25.39 	 2.7 	0.637 
	2003 	31.14 	 43.23 	37.53 	6.66 	44.16 	34.55 	 2.5 	0.716 
	2004 	41.42 	 52.91 	45.72 	6.87 	53.91 	41.37 	 2.5 	0.825 
	2005 	56.45 	 69.28 	57.38 	8.58 	69.13 	45.20 	 1.6 	0.850 
	Forecast 	  	  	  	  	  	  	  	  
	2006 	60.81 	 70.07 	59.62 	11.58 	71.77 	47.01 	 2.5 	0.850 
	2007 	61.61 	 70.99 	60.39 	10.84 	72.71 	47.62 	 2.5 	0.850 
	2008 	54.60 	 62.73 	53.48 	8.95 	64.25 	42.08 	 2.5 	0.850 
	2009 	50.19 	 57.53 	49.18 	7.87 	58.92 	38.59 	 1.5 	0.850 
	2010 	47.76 	 54.65 	46.75 	7.57 	55.97 	36.66 	 1.5 	0.850 
	Thereafter 	Various Escalation Rates 	  	  	  

	(1) 	
      This summary table identifies benchmark reference pricing
      schedules that might apply to a reporting issuer.

	(2) 	
      Inflation rates for forecasting prices and
  costs.

	(3) 	
      Exchange rates used to generate the benchmark reference
      prices in this table.

8

Notes: Product sale prices will reflect these reference prices
with further adjustments for quality and transportation to point of sale. 

Item 4.1 Reserves Reconciliation

	Item 4.1(1) 	
      As we first-commenced operations on October 1, 2005, we
        do not have historical information of a comparative or reconciling nature
        versus our December 31, 2005 reserves. 

Item 4.2 Future Net Revenue Reconciliation

As we first-commenced operations on October 1, 2005, we do not
have historical information of a comparative or reconciling nature versus our
December 31, 2005 reserves.

Item 5.1 Undeveloped Reserves

	Item 5.1(1) 	
      As we first-commenced operations on October 1, 2005, we
      do not have historical information of a comparative or reconciling nature
      versus our December 31, 2005 reserves. 

	Proved Undeveloped Reserves (Gross) as at December 31, 2005 –
      Constant Prices and Costs 
	Light and Medium Oil 	Heavy Oil 	Natural Gas 	Natural Gas Liquids 
	(mbbl) 	(mbbl) 	(mmcf) 	(mbbl) 
	- 	260 	562 	- 

Of our total proved reserves as at December 31, 2005, 26% were
undeveloped. Most of our undeveloped proved reserves are located where there is
capital required to tie in tested wells. A portion of these projects has already
been completed in the first quarter of 2006 and the remaining projects are
expected for completion by the end of 2006. One of the projects is not scheduled
for completion until the currently-producing zone is depleted. 

Item 5.1(2) Probable Undeveloped Reserves

As we first-commenced operations on October 1, 2005, we do not
have historical information of a comparative or reconciling nature versus our
December 31, 2005 reserves.

Of our total probable reserves as at December 31, 2005, we had
590.7 mbbls of heavy crude oil, 29 mmcf of solution gas and 220 mmcf of natural
gas that were classified as undeveloped. In aggregate, probable undeveloped
reserves comprised 49.5% of our total probable reserves.

In estimating all our probable reserves, the capital spending
required to develop such reserves has been factored into Fiscals 2006 and
2007.

Item 5.2 Significant Factors and Uncertainties

The process of evaluating reserves is inherently complex. It
requires significant judgements and decisions based on available geological,
geophysical, engineering and economic data. These estimates may change
substantially as additional data from ongoing development activities and
production performance becomes available and as economic conditions impacting
oil and gas prices and costs change. The reserve estimates contained herein are
based on current production forecasts, prices and economic conditions. These
factors and assumptions include among others: (i) historical production in the
area compared with production rates from analogous producing areas; (ii) initial
production rates; (iii) production decline rates; (iv) ultimate recovery of
reserves; (v) success of future development activities; (vi) marketability of
production; (vii) effects of government regulation; and (viii) other government
levies imposed over the life of the reserves. 

9

As circumstances change and additional data becomes available,
reserve estimates also change. Estimates are reviewed and revised, either upward
or downward, as warranted by the new information. Revisions are often required
due to changes in well performance, prices, economic conditions and governmental
restrictions. Revisions to reserve estimates can arise from changes in year-end
prices, reservoir performance and geologic conditions or production. These
revisions can be either positive or negative. 

Item 5.3 Future Development Costs

The table below sets out the future development costs deducted
in the estimation of future net revenue attributable to proved reserves (using
both constant and forecast prices and costs) and proved plus probable reserves
(using forecast prices only). 

	Future Development Costs 	 
    	 
    
	  	Total Proved 	Total Proved 	Total Proved Plus Probable 
	($000’s) 	Estimated Using 	Estimated Using 	Estimated Using 
	 Period 	Constant Prices and Costs 	Forecast Prices and Costs 	Forecast Prices and Costs 
	2006 	3,943 	3,943 	6,136 
	2007 	90
    	92
    	2,860 
	Total for all years 	  	  	  
	   
       - undiscounted 	4,033 	4,035 	8,996 
	     - 10% discounted 	3,972 	3,974 	8,518 

The future development costs are capital expenditures required
in the future for us to convert proved undeveloped reserves and probable
reserves into proved developed producing reserves. 

On an ongoing basis, we will typically use internally-generated
cash flow from operations, debt (where deemed appropriate) and new equity issues
if available on favourable terms to finance our capital investment program. When
financing corporate acquisitions, we may also assume certain future
liabilities.

10

Item 6.1 Oil and Gas Properties and Wells

Item 6.1(1) Important Properties, Plants, Facilities and
Installations

The following is information describing our important
properties, plants, facilities and equipment.

	Cypress/Chowade, 

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

	  	
       

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

	  	
       

	Land Holdings 	
      We have crown petroleum and natural gas leases over
      20,969 net acres (55,233 gross) for a weighted average working interest of
      38%. Of our total net acreage, approximately 77% is undeveloped.

	  	
       

	Seismic 	
      Our 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 Facilities 	
      We have four (1.8 net) producing gas wells, 33% of a
      central compression facility and 40% of an 8” 19-kilometer pipeline that
      crosses beneath the Halfway River and connects Cypress to the Sikanni Gas
      Plant. 

	  	
       

	Activities During the Three

      Month Period Ended

      December 31, 2005 	
      During the period, we averaged 1.0 mmcf/d from four
      producing gas wells or approximately 17% of our total production.
      Production operations were maintained during the period without
      significant capital expenditures. 

	  	
       

	Fiscal 2006 Outlook 	
      We plan to optimize current production levels by
      installing a new, sour, natural gas separator and re-configuring our
      existing dehydrator to minimize back pressure. 

	  	
       

	Orion, 

      British Columbia 	
      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 Aged 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 has the potential to contribute to long-term growth. 

	  	
       

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

11

	Land Holdings 	
      We hold under lease 46,467 net acres (65,946 gross) for a
      weighted average working interest of 70%. Approximately 93% of our net
      holdings are undeveloped. 

	  	
       

	Wells and Facilities 	
      We own a 15% gross overriding royalty interest
      (convertible to a 50% working interest after payout of our initial capital
      expenditures) in one cased and standing potential Jean Marie gas well and
      a 100% working interest in one standing potential Bluesky gas well. Both
      wells are cased and standing awaiting further evaluation and area
      development. 

	  	
       

		
      Two major pipeline systems terminate at the edges 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. 

	  	
       

	Activities During the Three 

      Month Period Ended 

      December 31, 2005 	
      We signed a farm-out agreement with an industry third
      party requiring them to drill one exploration test well on the property.
      

	  	
       

	Fiscal 2006 Outlook 	
      Subject to rig availability, the third party has
      committed, at their cost, to drill the exploration test well in the first
      quarter of 2006, targeting gas in the Bluesky formation. We will retain a
      15% gross overriding royalty in the well, converting to a 50% working
      interest upon payout of their initial capital expenditures. 

	  	
       

	Rigel, British Columbia 	
      Rigel is located in the plains region of northern British
      Columbia approximately 65 kilometres north of Fort. St. John and 40
      kilometres west of the British Columbia/Alberta border. 

	  	
       

	Geological Description 	
      The area has multi-zone potential for both oil and
      natural gas reservoirs. The main targets in the region include the
      Cretaceous- Dunlevy formation and the Triassic, Baldonnel, Charlie Lake,
      Halfway and Doig formations. 

	  	
       

	Land Holdings 	
      The area has multi-zone potential for both oil and
      natural gas reservoirs. The main targets in the region include the
      Cretaceous- Dunlevy formation and the Triassic, Baldonnel, Charlie Lake,
      Halfway and Doig formations. 

	  	
       

	Wells and Facilities 	
      We own one standing gas well (0.4 net). 

	  	
       

	Activities During the Three 

      Month Period Ended

      December 31, 2005 	
      We signed a farm-in agreement to earn a 40% working
      interest in 3,380 gross acres by drilling two commitment wells. We drilled
      the first commitment well and cased it as a potential gas well during the
      period. 

	  	
       

	Fiscal 2006 Outlook 	
      In the first quarter of Fiscal 2006, we commenced
      drilling of the second commitment well for a 50% working interest. We also
      plan to participate in the equipping and tie-in of the first standing gas
      well (0.4 net) in the first quarter. 

	  	
       

	Mantario East, 

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

12

	Geological Description 	
      The 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 Holdings 	
      We hold under lease 8,986 net acres (12,495 gross) for a
      weighted average working interest of 72%. Approximately 83% of our net
      holdings are undeveloped. 

	  	
       

	Wells and Facilities 	
      We have 16 (10.5 net) producing heavy oil wells, two (1.5
      net) standing gas wells and three (2.3 net) standing heavy oil wells at
      Mantario East. We also own 75% working interest in a heavy oil
      battery/heater-treater facility with a processing capacity of up to 3,500
      barrels per day. 

	  	
       

	Activities During the Three 

      Month Period Ended 

      December 31, 2005 	
      We drilled one (0.5 net) successful Viking gas well, one
      (0.8 net) successful horizontal heavy oil well and one (0.8 net)
      unsuccessful exploration well. In addition, we completed construction of
      our heater-treater facility at 75% working interest. We began operations
      on October 1, 2005 at an initial production rate of approximately 750
      boe/d from nine (6.5 net) producing heavy oil wells. By the end of the
      period, we had increased production to approximately 1,430 boe/d from 16
      producing heavy oil wells (11 net) or 90% of our total exit rate
      production. 

	  	
       

		
      The 13.20 API oil at Mantario East 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 non-company lands at Marengo, Mantario North, and Mantario East. The
      Mantario East pools 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. 

	  	
       

	Fiscal 2006 Outlook 	
      We have budgeted to drill 11 (8.3 net) development
      in-fill and field- delineation wells targeting Basal Mannville oil. Of the
      11 wells, one horizontal well commenced drilling in late 2005, two other
      horizontal and three vertical wells are scheduled for drilling in the
      first quarter. The remaining five vertical development wells are planned
      for the second and third quarters. We also plan to drill two (1.5 net)
      heavy- oil exploration wells and two (1.5 net) natural gas development
      wells in the second and third quarters. 

	  	
       

		
      Our Fiscal 2006 budget includes the cost of a gas
      gathering and field compression facility, capable of processing up to 1.5
      mmcf/d of gas from two (1.5 net) existing non-associated gas wells and
      from recovered solution gas currently being sent to flare at our oil
      battery. The gas gathering and field compression facility is scheduled for
      completion in the first quarter. 

	  	
       

		
      Funds have also been budgeted to acquire additional lands
      and seismic data in the area. 

	  	
       

	Other Non-Core Properties 	 In Saskatchewan, properties include
        Flaxcombe, Sandgren, Rapdan and Elmore, and in Alberta, Pica. In total,
        these properties comprise 3,465 net acres (8,711 gross acres) with an
        aggregate weighted average working interest of 40%. Of our total net acreage,
        96% is undeveloped. 

13

Item 6.1(2) Oil and Gas Wells

The following table sets forth the number and status of wells
in which we had a working interest as at December 31, 2005. The stated interests
are subject to landowner’s and other royalties, where applicable, in addition to
usual crown royalties and mineral taxes. All the following wells are located in
the British Columbia and Saskatchewan, as noted.

	  	 	Producing 	 	 	Non-Producing 	 
	  	 	Oil 	 	 	Natural Gas 	 	 	Oil 	 	 	Natural Gas 	 
		 	 Gross (1) 	 	 	Net
      (2)		 	Gross
      (1)		 	Net
      (2)		 	Gross
      (1)		 	Net
      (2)		 	Gross
      (1)		 	Net
      (2)	
	  	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	British Columbia 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	Cypress/ 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	     Chowade 	 	- 	 	 	- 	 	 	4 	 	 	1.8 	 	 	- 	 	 	- 	 	 	2 	 	 	0.6 	 
	Orion 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	2 	 	 	1.0 	 
	Rigel 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	1 	 	 	0.4 	 
	  	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	Saskatchewan 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	Mantario 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	  	 
	     East 	 	16 	 	 	10.5 	 	 	- 	 	 	- 	 	 	3 	 	 	2.3 	 	 	2 	 	 	1.5 	 
	Elmore 	 	3 	 	 	.2 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 
	Rapdan 	 	1 	 	 	.1 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 
	Flaxcombe 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	1 	 	 	0.5 	 
	Sandgren 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 	 	- 	 
	Total 	 	20 	 	 	10.8
    	 	 	4 	 	 	1.8
	 	 	3 	 	 	2.3
	 	 	8 	 	 	4.0
	 

	(1) 	
      “Gross” wells are defined as the total number of wells in
      which we have an interest.

	(2) 	
      “Net” wells are defined as the aggregate of the numbers
      obtained by multiplying each gross well by our percentage working interest
      therein.

Item 6.2 Undeveloped Properties Having No Attributed
Reserves

	Cypress/Chowade, 

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

	  	
       

	Land Holdings 	
      We have crown petroleum and natural gas leases over
      20,969 net acres (55,233 gross) for a weighted average working interest of
      38%. Of our total net acreage, approximately 77% is undeveloped.

	  	
       

	Fiscal 2006 Outlook 	
      We have no current plans to explore unproved acreage in
      Fiscal 2006. 

	  	
       

	Orion, 

      British Columbia 	
      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 Aged 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 has the potential to contribute
        to long-term growth. 

14

	Land Holdings 	 We hold under lease 46,467 net
        acres (65,946 gross) for a weighted average working interest of 70%. Approximately
        93% of our net holdings are undeveloped. 

	  	  

	Fiscal 2006 Outlook 	 We have no current plans to explore
        unproved acreage in Fiscal 2006. 

	  	  

	Fraser Valley 

      (Under Moratorium) 	 The property is located in the
        lower mainland area of southwest British Columbia near Vancouver. 

	  	  

	Land Holdings 	 Under a joint venture agreement
        with a large, multi-national energy company, 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. 

	  	  

	Activities During the Three 

      Month Period Ended

      December 31, 2005 	 We were inactive in the Fraser
        Valley area during this period. 

	  	  

	Fiscal 2006 Outlook 	 Areas offshore are subject to
        a restricted-access moratorium for petroleum and natural gas activities,
        however, discussions have been continuing 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 has
        been engaged in a public review to identify environmental and social concerns
        arising from offshore activities along the Pacific West Coast. A recent
        Federal Election has resulted in a change in government. As a result,
        the Provincial Government is expressing greater post-election optimism
        toward a joint Federal/Provincial lifting of the moratorium that may or
        may not occur in Fiscal 2006. 

	  	  

		 We have identified, through analysis
        of our proprietary onshore 2D seismic data, a large structural feature
        approximately 19 square kilometers in 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 have no current plans to explore
        unproved acreage in Fiscal 2006. 

Item 6.3 Forward Contracts

We have no forward contracts as at December 31, 2005.

15

Item 6.4 Additional Information Concerning Abandonment and
Reclamation Costs

The following table discloses the abandonment and reclamation
costs of our anticipated costs at December 31, 2005, calculated on an
undiscounted and a 10% discount rate with a portion thereof anticipated for
settlement in each of the next three years. We currently anticipate incurring
abandonment and reclamation costs in respect of 32.3 net wells, one compressor
and one battery site. 

	Abandonment and Reclamation Costs Net of Salvage Value
	 
    	 
    	 
    	 
    
	($000s) 	2006 	2007 	2008 	2009 	2010 	2011 	2012 	Remainder 	Total 	Discounted
	Facility
      Type 	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	at
      10% 
	Plant 	0 	0 	0 	0 	0 	0 	0 	33,000 	33,000 	13,995 
	  	  	  	  	  	  	  	  	  	  	  
	Well 	59,667 	15,000 	216,143 	208,500 	116,663 	335,490 	351,698 	324,034 	1,627,195 	667,056 
	  	  	  	  	  	  	  	  	  	  	  
	Total 	59,667 	15,000 	216,143 	208,500 	116,663 	335,490 	351,698 	357,034 	1,660,195 	681,051 

Item 6.5 Tax Horizon

We commenced operations on October 1, 2005 and as of the close
of our first quarter ended December 31, 2005, we were not required to pay income
taxes. Based on management’s current expectations, income taxes may become
payable in Fiscal 2006.

Item 6.6 Costs Incurred

The following table summarizes the capital expenditures made by
us on oil and natural gas properties for the three months ended December 31,
2005. 

	Costs
      Incurred 	 
    	 
    	 
    
	Property Acquisition Costs 	Exploration Costs 	Development Costs 
	(M$)
    	(M$)
    	(M$)
    
	Proved
      Properties 	Unproved Properties 	  	  
	- 	241 	1,245 	2,641 

We own interests in certain properties located in the Western
Provinces of Canada. They are as follows:

	Southern
      Saskatchewan 	British Columbia 	Alberta 
	Mantario East 	Cypress/Chowade 	Pica 
	Elmore 	Orion 	  
	Rapdan 	Fraser Valley 	  
	Flaxcombe 	Rigel 	  
	Sandgren 	  	  

Item 6.7 Exploration and Development Activities 

The following table sets forth the number of exploratory and
development wells which we completed during the three month period ended
December 31, 2005. 

	  	 	Exploratory Wells 	 	 	Development Wells 	 
	  	 	Gross
      (1)		 	Net
      (2)		 	Gross
      (1)		 	Net
      (2)	
	Oil Wells 	 	- 	 	 	- 	 	 	1 	 	 	0.8 	 
	Gas Wells 	 	1 	 	 	0.5 	 	 	1 	 	 	0.1 	 
	Dry Holes 	 	1 	 	 	0.8 	 	 	- 	 	 	- 	 
	Total Completed
      Wells 	 	2 	 	 	1.3
    	 	 	2 	 	 	0.9
    	 

16

	(1) 	
      “Gross” wells are defined as the total number of wells in
      which we have an interest.

	(2) 	
      “Net” wells are defined as the aggregate of the numbers
      obtained by multiplying each gross well by our percentage working interest
      therein.

Item 6.8 Production Estimates

The following table sets forth our estimated total production
volumes for Fiscal 2006. Our fields at Mantario East are the only fields that
individually meet or exceed 20% of our estimated total production. 

	  	Light
      & Medium Oil 	Heavy
      Oil 	Natural
      Gas 	Natural
      Gas Liquids 
	Total Proved 	(mbbl) 	(mbbl) 	(mmcf) 	(mbbl) 
	All Fields 	365 	534,968 	499,989 	- 
	Mantario East 	-
	534,968 	220,825 	-
  

Item 6.9 Production History

	Item 6.9(1) 	
      As we first-commenced operations on October 1, 2005, we
      do not have historical production information of a comparative nature for
      quarters prior to our first quarter ended December 31, 2005.
  

The following table sets forth certain information in respect
of production, product prices received, royalties, production costs and netbacks
received by us for the three months ended December 31, 2005.

	  	Three Months Ended 
	  	Dec.
      31, 2005 
	Average Daily Production 	  
	Light and Medium Oil (bbl/d) 	- 
	Heavy Oil (bbl/d) 	916 
	Natural Gas (mcf/d) 	927 
	Natural Gas Liquids (bbl/d) 	- 
	Average Net
      Prices Received(1) 	  
	Light and Medium Oil ($/bbl) 	- 
	Heavy Oil ($/bbl) 	30.36 
	Natural Gas ($/mcf) 	11.92 
	Natural Gas
      Liquids ($/bbl) 	-
  
	Royalties 	  
	Light and Medium Oil ($/bbl) 	- 
	Heavy Oil ($/bbl) 	7.77 
	Natural Gas ($/mcf) 	2.68 
	Natural Gas Liquids ($/bbl) 	- 
	Production
      Costs 	  
	Light and Medium Oil ($/bbl) 	- 
	Heavy Oil ($/bbl) 	9.00 
	Natural Gas ($/mcf) 	2.91 
	Natural Gas
      Liquids ($/bbl) 	-
  
	Netback Received 	  
	Light and Medium Oil ($/bbl) 	- 
	Heavy Oil ($/bbl) 	13.59 
	Natural Gas ($/mcf) 	6.33 
	Natural Gas Liquids ($/bbl) 	- 

(1) Unit production cost measures by reserve
category require certain allocations to by-products.

17

	Item 6.9(2) 	
      The following table shows our total production before
      royalties during the three month period ended December 31, 2005 from our
      core property, Mantario East. 

	  	Light
      & Medium Oil 	Heavy
      Oil 	Natural
      Gas 	Natural
      Gas Liquids 
	Total Proved 	(mbbl) 	(mbbl) 	(mmcf) 	(mbbl) 
	Mantario East 	- 	84 	- 	- 

18

Form 51-101F2

REPORT ON RESERVES DATA BY INDEPENDENT 
QUALIFIED
RESERVES EVALUATOR OR AUDITOR

Report on Reserves Data

To the Board of Directors of Shellbridge Oil & Gas, Inc.
(the “Company”):

	1. 	
      We have evaluated the Company’s Reserves Data as at
      December 31, 2005. The reserves data consist of the
  following:

	 	(a)(i) 	 	proved and proved plus probable oil and gas
      reserves estimated as at December 31, 2005 using forecast prices and
      costs; and 
	 	 	 	 
	 	(ii) 	 	the related estimated future net revenue; and
    
	 	 	 	 
	 	(b)(i) 	 	proved oil and gas reserve quantities were
      estimated as at December 31, 2005 using constant prices and costs; and
  
	 	 	 	 
	 	(ii) 	 	the related estimated future net revenue.
  

	2. 	
      The Reserves Data are the responsibility of the Company’s
      management. Our responsibility is to express an opinion on the Reserves
      Data based on our evaluation.

	 	 
		
      We carried out our evaluation in accordance with
      standards set out in the Canadian Oil and Gas Evaluation Handbook (the
      “COGE Handbook”), prepared jointly by the Society of Petroleum Evaluation
      Engineers (Calgary Chapter) and the Canadian Institute of Mining,
      Metallurgy & Petroleum (Petroleum Society).

	 	 
	3. 	
      Those standards require that we plan and perform an
      evaluation to obtain reasonable assurance as to whether the reserves data
      are free of material misstatement. An evaluation also includes assessing
      whether the reserves data are in accordance with principles and
      definitions presented in the COGE Handbook.

19

	4. 	
      The following table sets forth the estimated future net
      revenue attributed to proved plus probable reserves, estimated using
      forecast prices and costs on a before tax basis and calculated using a
      discount rate of 10%, included in the reserves data of the Company
      evaluated by us as of December 31, 2005, and identifies the respective
      portions thereof that we have audited, evaluated and reviewed and reported
      on to the Company’s management and Board of
Directors:

  	 	Independent
      	  	 
      	Net Present Value of Future Net Revenue 
	 	Qualified 	  	  	 
      	(10% Discount Rate) 	 
      
	 	Reserves 	Description 	Location of 	  	  	  	  
	 	Evaluator or 	 and Preparation Date 	Reserves 	Audited 	Evaluated 	Reviewed 	Total 
	 	Auditor
      	 of
        Evaluation Report 	(Country)
      	(M$)
      	(M$)
      	(M$)
      	(M$)
      
	 	Sproule 	Evaluation of the P&NG 	Canada 	  	  	  	  
	 	  	Reserves of Shellbridge 	  	  	  	  	  
	 	  	Oil & Gas, Inc., as of 	  	  	  	  	  
	 	  	December 31, 2005, 	  	  	  	  	  
	 	  	prepared November 	  	  	  	  	  
	 	  	2005 to January
        2006. 	  	  	  	  	  
	 	Total 	  	  	Nil 	31,572 	Nil 	31,572 

	5. 	
      In our opinion, the reserves data evaluated by us have,
      in all material respects, been determined and are presented in accordance
      with the COGE Handbook.

	 	 
	6. 	
      We have no responsibility to update the report referred
      to in paragraph 4 for events and circumstances occurring after its
      preparation date.

	 	 
	7. 	
      Because the reserves data are based on judgements
      regarding future events, actual results will vary and the variations may
      be material.

Executed as to our report referred to above:

Sproule Associates Limited 
Calgary, Alberta 
January 27,
2006

“Cameron P. Six”
Cameron P. Six, P.Eng.

Associate

“Michael W. Maughan”
Michael W. Maughan, C.P.G.,
P.Geol. 
Manager, Geoscience, & Associate

“Harry J. Helwerda”
Harry J. Helwerda, P.Eng.

Vice-President, Engineering

20

Form 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS
DISCLOSURE

This is the form referred to in item 3 of section 2.1 of
National Instrument 51-101 Standards of Disclosure for Oil and Gas
Activities (“NI 51-101”). This form does not apply in British
Columbia 

	1. 	
      Terms to which a meaning is ascribed in NI 51-101
      have the same meaning in this form.

	 	 
	2. 	
      The report referred to in item 3 of section 2.1 of NI
      51-101 shall in all material respects be as
follows:

Report of Management and Directors On Reserves Data and
Other Information

Management of Shellbridge Oil & Gas, Inc. (the “Company”)
are responsible for the preparation and disclosure of information with respect
to the Company’s oil and gas activities in accordance with securities regulatory
requirements. This information includes reserves data, which consist of the
following: 

	 	a) 	
      proved and proved plus probable oil and gas reserves
      estimated as at December 31, 2005 using forecast prices and
  costs;

	 	 	 
	 	b) 	
      the related estimated future net revenue;

	 	 	 
	 	c) 	
      proved oil and gas reserves estimated as at December 31,
      2005 using constant prices and costs; and

	 	 	 
	 	d) 	
      the related estimated future net
  revenue.

Sproule Associates Limited, an independent qualified reserves
evaluator, has evaluated the Company’s reserves data. The report of Sproule
Associates Limited is presented above on Form 51-101F2. 

The Reserves Audit Committee of the Board of Directors of the
Company has: 

	 	a) 	
      reviewed the Company’s procedures for providing
      information to Sproule Associates Limited;

	 	 	 
	 	b) 	
      met with Sproule Associates Limited to determine whether
      any restrictions affected the ability of Sproule Associates Limited to
      report without reservation; and

	 	 	 
	 	c) 	
      reviewed the reserves data with Management and Sproule
      Associates Limited.

The Reserves Audit Committee of the Board of Directors has
reviewed the Company’s procedures for assembling and reporting other information
associated with oil and gas activities and has reviewed that information with
Management. The Board of Directors has, on the recommendation of the Reserves
Audit Committee, approved:

21

	 	a) 	
      the content and filing with securities regulatory
      authorities of the reserves data and other oil and gas
  information;

	 	 	 
	 	b) 	
      the filing of the report of Sproule Associates Limited on
      the reserves data; and

	 	 	 
	 	c) 	
      the content and filing of this
report.

The reserves data are based on judgements regarding future
events. Actual results may vary and the variations may be material. 

“Wayne J.
Babcock”
_______________________________
Wayne J.
Babcock
President & Chief Executive Officer 

“Michael A.
Bardell”
_______________________________
Michael A. Bardell

Chief Financial Officer

“William B.
Thompson”
_______________________________
William B. Thompson

Director 

“John Greig”
_______________________________
John
Greig 
Director 

22Filed by Automated Filing Services Inc. (604) 609-0244 - Shellbridge Oil & Gas, Inc. - Exhibit 4.9

SHELLBRIDGE OIL & GAS, INC. 
(the
"Corporation")

AUDIT COMMITTEE CHARTER

PURPOSE

The purpose of this Charter is to outline the role of the Audit
Committee (the "Committee") and the responsibilities assigned to it by the Board
of Directors (the "Board") of the Corporation. The main function of the
Committee is to assist the Board in fulfilling its oversight responsibilities
with respect to the accounting and financial reporting processes of the
Corporation and reviewing the financial information to be provided to the
Corporation's stockholders and others.

The Committee shall have the power to conduct or authorize
investigations into any matters within the Committee's scope of
responsibilities. In connection with such investigations or otherwise in the
course of fulfilling its responsibilities under this Charter, the Committee
shall have the authority to retain special legal, accounting or other
consultants or advisors to advise it, and to authorize the payment of the fees
and expenses of such consultants or advisors, and may request any officer or
employee of the Corporation, its outside legal counsel or outside auditor to
attend a meeting of the Committee or to meet with any members of, or consultants
or advisors to, the Committee. The Committee shall also have the authority to
direct the funding by the Corporation of ordinary administrative expenses of the
Committee that are necessary or appropriate in carrying out its duties. The
Committee shall have unrestricted access to personnel and information, and any
resources necessary to carry out its responsibilities. In this regard, the
Committee may direct internal audit personnel to particular areas of
examination.

The Corporation's external auditor shall be accountable to the
Committee and the Board, and the Committee shall have the authority and
responsibility to select, oversee, approve the compensation of, and, where
appropriate, replace the external auditor. In the course of fulfilling its
specific responsibilities hereunder, the Committee shall strive to maintain open
avenues of communication between the Corporation's external auditor and the
Board.

Although the Committee shall have the responsibilities and
powers set forth in this Charter, it shall not be the duty of the Committee to
plan or conduct audits or to determine whether the Corporation's financial
statements are complete, accurate, or in accordance with generally accepted
accounting principles. These are the responsibilities of management and the
external auditor. Nor shall it be the duty of the Committee to conduct
investigations or to assure compliance with laws and regulations or the
Corporation's own policies.

The specific responsibilities of the Committee are summarized
below.

COMPOSITION

The Committee shall consist of not less than three Directors as
determined and appointed by the Board, all of whom shall qualify as independent
Directors as determined in accordance with applicable securities laws and stock
exchange or quotation system rules (collectively, the "Regulatory
Requirements"). Generally, each member of the Committee must be free from any
relationship that would interfere with the exercise of his or her independent
judgment.

Committee members shall not simultaneously serve on the audit
committees of more than two other public companies, unless the Board determines
that such simultaneous service will not impair the ability of the relevant
members to effectively serve on the Committee.

Any member may be removed or replaced at any time by the Board
and shall, in any event, cease to be a member of the Committee upon ceasing to
be a member of the Board. Where a vacancy occurs at any time in the membership
of the Committee, it may be filled by the Board at any regular or special
meeting.

The Board shall appoint a Chair of the Committee. If the Chair
of the Committee is not present at any meeting of the Committee, one of the
other members of the Committee present at the meeting shall be chosen to preside
by a majority of the members of the Committee present at such meeting.

MEETINGS

The Committee shall meet at least quarterly on such dates and
at such times and places as determined by the Chair of the Committee. The Chair
or any other member of the Committee may call additional meetings as required or
appropriate. The Committee shall have the right to determine who shall, and who
shall not, be present at any time during a meeting of the Committee. The
Committee shall also meet separately from time to time with the Corporation's
management, internal auditors and external auditors.

The Board shall be kept informed of the Committee's activities
by a report from the Chair of the Committee following each Committee
meeting.

RESPONSIBILITIES OF THE COMMITTEE

General Duty of Members

The duties and responsibilities of a member of the Committee
are in addition to those duties set out for a member of the Board.

Responsibilities

Financial Statements and Other Financial Disclosure

	1. 	
      Discuss and review with management and the external
      auditors the Corporation's annual audited financial statements, notes to
      the financial statements, annual Management Discussion and Analysis
      ("MD&A") and other related documents prior to their filing or
      distribution, including consideration of:

	 	 	 
		(a) 	
      Accounting principles, practices and significant
      management estimates and judgments.

	 	 	 
		(b) 	
      The external auditors' audit examination of the financial
      statements and their audit report.

	 	 	 
		(c) 	
      Policies and practices with respect to off-balance sheet
      transactions and trading and hedging activities.

	 	 	 
	2. 	
      Discuss and review with management and the external
      auditors any significant changes required in the external auditors' audit
      plan, any material issues or disputes encountered by the external auditors
      during the course of the audit and any other matters related to the
      conduct of the audit.

PAGE 2

	3. 	
      Based on discussions with management and the external
      auditors, review and formally recommend approval by the Board of the
      Corporation's annual audited financial statements, MD&A and other
      significant financial disclosure contained in the Corporation's Form 20-F
      (AIF) and annual Information Circular.

	 	 
	4. 	
      Review and discuss with management and the external
      auditors the Corporation's quarterly unaudited financial
      statements, MD&A and other related documents.

	 	 
	5. 	
      Review and discuss with management other financial
      filings and disclosure, including press releases and earnings guidance
      contained in any filings with the securities regulators or news releases
      or materials provided to analysts or rating
agencies.

External Auditors

	6. 	
      Subject to applicable Regulatory Requirements and rights
      of shareholders, assume direct responsibility for the appointment,
      compensation, retention and oversight of the work of the external auditors
      (including the resolution of disagreements between management and the
      auditors regarding financial reporting) for the purpose of preparing or
      issuing an audit report or performing any other audit, review or attest or
      permitted non-audit services for the Corporation. The external auditors
      shall report directly to the Committee.

	 	 	 
	7. 	
      Review and approve the services to be provided by the
      external auditors, whether audit or non-audit, (including the fees and
      terms thereof) prior to the commencement of such services (with the
      exception of de minimus non-audit services described under
      applicable Regulatory Requirements which are approved by the Committee
      prior to the completion of the audit).

	 	 	 
	8. 	
      Identify categories of non-audit services that the
      external auditors must not provide to the Corporation.

	 	 	 
	9. 	
      Review and evaluate the external auditors' engagement
      letter and estimated and final compensation for audit and non-audit
      services.

	 	 	 
	10. 	
      Meet regularly with the external auditors (independent of
      management), either at the request of the external auditors or on the
      Committee's own initiative, to consider matters that the external auditors
      believe should be discussed privately with the Committee.

	 	 	 
	11. 	
      Review and discuss with the external auditors:

	 	 	 
		(a) 	
      Critical accounting policies and practices followed by
      the Corporation.

	 	 	 
		(b) 	
      All alternative treatments within generally accepted
      accounting principles that have been discussed with management, including
      the ramifications of each alternative disclosure and treatment, and the
      treatment preferred by the external auditors.

	 	 	 
		(c) 	
      Other material written communications between the
      external auditors and management.

	 	 	 
	12. 	
      Consider and review with the external auditors and
      management:

	 	 	 
		(a) 	
      Significant findings during the year and management's
      responses thereto.

PAGE 3

		(b) 	
      Difficulties encountered in the course of audits,
      including any restrictions on the scope of their work or access to
      required information.

	 	 	 
		(c) 	
      Any disagreements between the external auditors and
      management during the course of the audit, including any restrictions on
      the scope of their work or access to required information.

	 	 	 
		(d) 	
      Proposed changes in accounting standards, policies or
      practices and the impact of such changes on the Corporation's financial
      reporting practices.

	 	 	 
		(e) 	
      Planned changes in the external auditors' audit
    plan.

	 	 	 
		(f) 	
      The mandate and performance of management responsible for
      the internal audit.

	 	 	 
		(g) 	
      Significant risks or exposures identified by management
      or the external auditors and assess the steps management has taken to
      minimize such risks to the Corporation.

	 	 	 
	13. 	
      Review and discuss with the external auditors all
      relationships that the external auditors and their affiliates have with
      the Corporation and its affiliates in order to assess the external
      auditors' independence, including, without limitation, (i) ensuring the
      receipt of and reviewing a written statement from the external auditors
      describing all relationships that may reasonably be thought to bear on the
      independence of the external auditors, (ii) discussing any disclosed
      relationships or services that the external auditors believe may affect
      the objectivity and independence of the external auditors, and (iii)
      recommending that the Board take appropriate action in response to such
      review to satisfy itself of the external auditors' independence.

	 	 	 
	14. 	
      Review and approve the Corporation's hiring policies
      regarding partners, employees and former partners and employees of the
      Corporation's current and former external
auditors.

Internal Control Over Financial Reporting

	15. 	
      Review with management management's report on the
      effectiveness of the Corporation's system of internal control for
      identifying and managing principal business risks.

	 	 
	16. 	
      Meet on a periodic basis separately with the members of
      management responsible for internal audit.

	 	 
	17. 	
      Review with the external auditors the external auditors'
      report or attestation regarding the Corporation's internal control over
      financial reporting.

	 	 
	18. 	
      Review any extraordinary or unusual transactions or
      payments which come to the attention of the Committee, including related
      party transactions between the Corporation and any officers, directors or
      affiliates of any officers or directors, which transactions shall be
      subject to Committee approval.

	 	 
	19. 	
      Review annually the amounts and types of expenses of the
      Corporation's executive officers and including their use of corporate
      assets the results of the external auditors' review of such
    expenses.

	 	 
	20. 	
      Establish procedures for the receipt and treatment of
      complaints regarding accounting, internal accounting controls or auditing
      matters, including a procedure for the confidential and
  anonymous

PAGE 4

submission of complaints and concerns by employees of the
Corporation regarding questionable accounting or auditing matters as required
under applicable Regulatory Requirements.

Other Matters

	21. 	
      Review any legal or regulatory matters, including
      correspondence with regulators and governmental agencies, that may have a
      material impact on the Corporation's financial statements or other
      financial disclosure.

	 	 
	22. 	
      Conduct an annual review and assessment of the adequacy
      of this Charter and the functioning of the Committee and, if necessary,
      make recommendations to the Board as to proposed changes to this
      Charter.

The Committee may, in its sole discretion, delegate all or a
portion of its responsibilities to a subcommittee made up of members of the
Committee.

As at January 25, 2006

PAGE 5

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