Filed by Automated Filing Services Inc. (604) 609-0244 - Tag Oil Ltd. - Exhibit 4.9






EVALUATION OF THE P&NG RESERVES 

OF 

TAG OIL LTD. 

IN THE CHEAL AREA OF NEW ZEALAND 

(As of March 31, 2007) 


 





	Copies: 	TAG Oil Ltd. (5 copies) 
	  	Sproule International Limited (1 copy) 
	  	Electronic (1) 
	  	  
	Project No.: 	3219.70414 
	  	  
	Prepared For: 	TAG Oil Ltd. 
	  	  
	Authors: 	Douglas J. Carsted, P.Geol., Project Leader
  
	  	Jeff Duer, P. Eng. 
	  	Barrie F. Jose, P.Geoph. 
	  	  
	Exclusivity: 	
      This report has been prepared for the exclusive use of
      TAG Oil Ltd., and shall not be reproduced, distributed, or made available
      to any other company or person, regulatory body, or organization without
      the knowledge and written consent of Sproule International Limited, and
      without the complete contents of the report being made available to that
      party. 








	Table of Contents
      — Page 1 


Table of Contents 

	Introduction 	 	  
	  	 	  
	  	 	Field Operations 
	  	 	Historical Data, Interests and Burdens 
	  	 	Evaluation Standards 
	  	 	Evaluation Procedures 
	  	 	Evaluation Results 
	 	 	BOE Cautionary Statement  
	  	 	Forward-Looking Statements 
	  	 	Exclusivity 
	  	 	Certification 
	  	 	Permit to Practice 
	  	 	Certificates 
	  	 	  
	  	 	  
	Summary 	 	  
	  	 	  
	                  
    	 Table S-1	Summary of the Evaluation of the P&NG
      Reserves of 
	  	 	TAG Oil Ltd.in the 
	  	 	Cheal Area of New Zealand 
	 	 	(As of March 31, 2007), 
	  	 	Before Income Tax 
	  	 	  
	                  
    	 Table S-2	Summary of Selected Price Forecasts 
	 	 	(Effective March 31, 2007) 
	  	 	  
	 	 Table S-3	Summary of Reserves and Net Present Values
  
	  	 	Total Proved Plus Probable Plus Possible
      Reserves — 
	  	 	Before Income Tax 
	  	 	  
	 	 Table S-3A	Summary of Reserves and Net Present Values
  
	  	 	Total Proved Plus Probable Reserves — 
	  	 	Before Income Tax 
	  	 	  
		 Table S-3B 	Summary of Reserves and Net Present Values
  
	  	 	Total Proved Undeveloped — 
	  	 	Before Income Tax 









	Table of Contents
      — Page 2 



	 	Table S-3C 	Summary of Reserves and Net Present Values
  
	 	  	Total Probable Undeveloped Reserves — 
	 	 	Before Income Tax 
	 	  	  
	 	Table S-3D 	Summary of Reserves and Net Present Values
  
	 	  	Total Possible Undeveloped Reserves — 
	 	 	Before Income Tax 
	 	  	  
	 	Figure S-1 	Map of New Zealand Highlighting Petroleum

	 	  	Exploration Permit (PEP) 38738 
	 	  	  
	 	Figure S-2 	Daily Company Gross Barrels of Oil Equivalent
    
	 	  	(BOE) Forecast 
	 	  	  
	 	Figure S-3 	Annual Cash Flow (Before Income Tax) 
	 	  	  
	 	Figure S-4 	Net Present Values (Before Income Tax) 
	 	  	  
	 	  	  
	 Discussion 		  
	 	  	  
	 	  	General 
	 	  	Geophysics 
	 	  	Geology 
	 	  	Estimation of Reserves and Production Forecasts
    
	 	  	Pricing 
	 	  	Operating and Capital Costs 
	 	 	Royalties and
  Taxes  
	 	 	Net Present
  Values  
	 	  	  
	 	Table 1 	Cheal, New Zealand, Volumetric Reservoir Data
    
	 	  	And Estimates of Reserves 
	 	  	  
	 	Table 2 	Cheal, New Zealand, Estimates of Reserves

	 	  	and Net Present Values 
	 	  	  
	 	Table 3 	Cheal, New Zealand, Forecasts of Production
  
	 	  	and Net Revenue 



 





	Table of Contents
      — Page 3 



	Constant Prices and Costs
  
	 	  	  
	 	Table C-1 	Summary of the Evaluation of the P&NG
      Reserves 
	 	 	of TAG Oil Ltd.in
    the  
	 	  	Cheal Area of New Zealand 
	 	  	(As of March 31, 2007), 
	 	 	Before Income
  Tax  
	 	  	  
	 	Table C-2 	Forecasts of Production and Net Revenue 
	 	  	  
	 	  	  
	National Instrument 51-101
    
	 	  	  
	 	  	Forecast Prices and Costs 
	 	  	Constant Prices and Costs 
	 	  	  
	 	Form 51-101F2 	  
	 	  	  
	 	Table 1 	Summary of Oil and Gas Reserves, 
	 	  	as of March 31, 2007 — 
	 	  	Forecast Prices and Costs 
	 	  	  
	 	Table 2 	Summary of Net Present Values 
	 	  	of Future Net Revenue, 
	 	  	as of March 31, 2007 — 
	 	  	Forecast Prices and Costs 
	 	  	  
	 	Table 3 	Total Future Net Revenue (Undiscounted), 
	 	  	as of March 31, 2007 — 
	 	  	Forecast Prices and Costs 
	 	  	  
	 	Table 4 	Net Present Value of Future Net 
	 	  	Revenue by Production Group, 
	 	  	as of March 31, 2007 — 
	 	  	Forecast Prices and Costs 
	 	  	  
	 	Table 5 	Summary of Pricing and Inflation Rate 
	 	  	Assumptions, as of March 31, 2007 — 
	 	  	Forecast Prices and Costs 



 





	Table of Contents
      — Page 4 



	 	Table 6 	Summary of Oil and Gas Reserves 
	 	  	as of March 31, 2007 — 
	 	  	Constant Prices and Costs 
	 	  	  
	 	Table 7 	Summary of Net Present Values of 
	 	  	Future Net Revenue, 
	 	  	as of March 31, 2007 — 
	 	  	Constant Prices and Costs 
	 	  	  
	 	Table 8 	Total Future Net Revenue (Undiscounted), 
	 	  	as of March 31, 2007 — 
	 	  	Constant Prices and Costs 
	 	  	  
	 	Table 9 	Net Present Value of Future Net 
	 	  	Revenue by Production Group, 
	 	  	as of March 31, 2007 — 
	 	  	Constant Prices and Costs 
	 	  	  
	 	Table 10 	Summary of Pricing and Inflation Rate 
	 	  	Assumptions as of March 31, 2007 
	 	  	Constant Prices and Costs 
	 	  	  
	Figures 	  
	 	  	  
	 	Figure 1 	Map of New Zealand highlighting 
	 	  	Petroleum Exploration Permit (PEP) 38738 
	 	  	  
	 	Figure 2 	Seismic Control & PEP 38738 
	 	  	  
	 	Figure 3 	3D Perspective View of Interpreted Horizon Data
    
	 	  	Provided by Company 
	 	  	  
	 	Figure 4 	3D Perspective View of Fault Sticks Provided by
      Company 
	 	  	  
	 	Figure 5 	Faults Re-interpreted by Sproule 
	 	  	  
	 	Figure 6 	Time Structure Interpreted by Sproule
  



 





	Table of Contents
      — Page 5 



	 	Figure 7 	Depth Structure at Sandstone #3
      and Fault Framework Interpreted 
	 	 	by Sproule 
	 	 	 
	 	Figure 8 	Depth Structure on Sandstone #3
      with Well Tops 
	 	 	 
	 	Figure 9 	Mt. Messenger Sandstone #3 Depth
      Structure Map 
	 	 	 
	 	Figure 10 	Mt. Messenger Sandstone #2 Depth
      Structure Map 
	 	 	 
	 	Figure 11 	Scaled-up Porosity from Well Logs
      within Petrel Model 
	 	 	 
	 	Figure 12 	Petrophysical Model of Porosity
      for Sandstone #3 
	 	 	 
	 	Figure 13 	Mt. Messenger Sandstone #3 Net Pay
      Map 
	 	 	 
	 	Figure 14 	Mt. Messenger Sandstone #2 Net Pay
      Map 
	 	 	 
	Appendices 	 
	 	 
	 	Appendix A
	Definitions 
	 	 	 
	 	Appendix B
	Abbreviations




 





	Introduction —
      Page 1 


Introduction 

This report was prepared by Sproule International Limited
(“Sproule”) at the request of Mr. Drew Cadenhead, President and Chief Executive
Officer, TAG Oil Ltd. TAG Oil Ltd. is hereinafter referred to as "the Company."
The effective date of this report is March 31, 2007.

The report consists of an evaluation of the P&NG reserves
associated with the Company's interest in the Cheal Field, New Zealand. It was
prepared during the months of May and June 2007, for the purpose of evaluating
the Company’s P&NG reserves according to Canadian Oil and Gas Evaluation
Handbook (COGEH) reserve definitions that are consistent with the standards of
National Instrument 51-101. This report was prepared for the Company’s corporate
purposes.

This report is included in one volume, which consists of an
Introduction, Summary, Discussion, Constant Prices and Costs, National
Instrument 51-101, and Appendices. The Introduction includes the summary of the
evaluation standards and procedures and pertinent author certificates; the
Summary includes high-level summaries of the evaluation; and the Discussion
includes general commentaries pertaining to the evaluation of the P&NG
reserves. The Constant Prices and Costs section shows the Company’s total
reserves and cash flows under the assumption of constant prices and costs. The
National Instrument 51-101 section presents Form 51-101 F2—Report on Reserves
Data by Independent Qualified Reserves Evaluator or Auditor, Tables 1 to 5 using
Forecast Prices and Costs, Tables 6 to 10 using Constant Prices and Costs.
Reserves definitions, abbreviations, units, and conversion factors are included
in Appendices A and B. 

Field Operations 

In the preparation of this evaluation, a field inspection of
the properties was not performed by Sproule. The relevant engineering data were
made available by the Company or obtained from public sources and the
non-confidential files at Sproule. No material information regarding the
reserves evaluation would have been obtained by an on-site visit. 


 





	Introduction —
      Page 2 


Historical Data, Interests and Burdens 

	1. 	
      All historical production, well data, revenue and expense
      data, product prices actually received, and other data that were obtained
      from the Company or from public sources were accepted as represented,
      without any further investigation by Sproule.

	 	 
	2. 	
      Property descriptions and details of interests held, as
      supplied by the Company, were accepted as represented. No investigation
      was made into either the legal titles held or any operating agreements in
      place relating to the subject properties.

	 	 
	3. 	
      Lessor and overriding royalties and other burdens were
      obtained from the Company. No further investigation was undertaken by
      Sproule.



Evaluation Standards 

This report has been prepared by Sproule using current
geological and engineering knowledge, techniques and computer software. It has
been prepared within the Code of Ethics of the Association of Professional
Engineers, Geologists and Geophysicists of Alberta (“APEGGA”). This report
adheres in all material aspects to the “best practices” recommended in the COGE
Handbook, which are in accordance with principles and definitions established by
the Calgary Chapter of the Society of Petroleum Evaluation Engineers. The COGE
Handbook is incorporated by reference in National Instrument 51-101. 

Evaluation Procedures 

	1. 	
      The Company provided Sproule with recent revenue
      statements to determine certain economic parameters.

	 	 
	2. 	
      The forecasts of product prices used in this evaluation
      were based on Sproule’s March 31, 2007 price forecasts.

	 	 
	3. 	
      Well abandonment and disconnect costs were included in
      this report at the entity level for wells which have reserves assigned. No
      allowances for reclamation or salvage values were
made.




 





	Introduction —
      Page 3 


Evaluation Results 

	1. 	
      The analysis of individual properties as reported herein
      was conducted with the context and scope of an evaluation of a unique
      group of properties in aggregate. Use of this report outside of this scope
      may not be appropriate.

	 	 
	2. 	
      The accuracy of reserves estimates and associated
      economic analysis is, in part, a function of the quality and quantity of
      available data and of engineering and geological interpretation and
      judgment. Given the data provided at the time this report was prepared,
      the estimates presented herein are considered reasonable. However, they
      should be accepted with the understanding that reservoir and financial
      performance subsequent to the date of the estimates may necessitate
      revision. These revisions may be material.

	 	 
	3. 	
      The net present values of the reserves presented in this
      report simply represent discounted future cash flow values at several
      discount rates. Though net present values form an integral part of fair
      market value estimations, without consideration for other economic
      criteria, they are not to be construed as Sproule’s opinion of fair market
      value.

	 	 
	4. 	
      The dollar values presented throughout the report are in
      United States dollars, unless otherwise stated. An exchange rate of 0.7157
      United States dollars per New Zealand dollar was used to convert budget
      information supplied by the Company. This rate was based on the exchange
      rate for March 30, 2007, as obtained from the Bank of Canada
    website.

	 	 
	5. 	
      Due to rounding, certain totals may not be consistent
      from one presentation to the next.



BOE Cautionary Statement 

BOE’s (or ‘McfGE’s’ or other applicable units of equivalency)
may be misleading, particularly if used in isolation. A BOE conversion ratio of
6 Mcf:1 bbl (or ‘An McfGE conversion ratio of 1 bbl: 6 Mcf’) is based on an
energy equivalency conversion method primarily applicable at the burner tip and
does not represent a value equivalency at the wellhead. 

Forward-Looking Statements 

This report may contain forward-looking statements including
expectations of future production revenues and capital expenditures. Information
concerning reserves may also be deemed to be forward-looking as estimates
involve the implied assessment that the reserves described can be profitably
produced in future. These statements are based on current expectations that
involve a number of risks and uncertainties, which could cause actual results to
differ from those anticipated. These risks include, but are not limited to: the
underlying risks of the oil and gas 


 





	Introduction —
      Page 4 


industry (i.e., operational risks in development, exploration
and production; potential delays or changes in plans with respect to exploration
or development projects or capital expenditures; the uncertainty of reserves
estimations; the uncertainty of estimates and projections relating to
production; costs and expenses, and health, safety and environmental factors),
commodity price and exchange rate fluctuation. 

Exclusivity 

This report has been prepared for the exclusive use of TAG Oil
Ltd, and shall not be reproduced, distributed, or made available to any other
company or person, regulatory body, or organization without the knowledge and
written consent of Sproule International Limited, and without the complete
contents of the report being made available to that party.


 





	Introduction —
      Page 5 



	Certification 
	  
	Report Preparation 
	 
	
      The report entitled “Evaluation of the P&NG Reserves
      of TAG Oil Ltd.(As of March 31, 2007),” was prepared by the following
      Sproule personnel: 

	



	 	Original signed by Michael W.
      Maughan, C.P.G., P.Geol. 
	 	 
	 	for 	 Douglas J. Carsted, P.Geol. 
	 	  	Project Leader; 
	 	  	 Vice-President, Geoscience 
	 	  	15 / 06 /2007 dd/mm/yr 
	 	  	 
	 	  	 
	 	  	 
	 	  	 
	 	  	Original signed by Jeff Duer 
	 	  	 Jeff Duer, P.Eng. 
	 	  	 Reservoir Engineer 
	 	  	15 / 06 /2007 dd/mm/yr 
	 	  	 
	 	  	 
	 	  	 
	 	  	 
	 	  	 Original signed by Barrie F. Jose 
	 	  	 Barrie F. Jose, P.Geoph. 
	 	  	 Manager, Geoscience 
	 	  	15 / 06 /2007 dd/mm/yr
  









	Introduction —
      Page 6 


Sproule Executive Endorsement 

This report has been reviewed and endorsed by the following
Executive of Sproule: 

	 	  	Original signed by Robert N. Johnson, P.Eng. 
	 	for 	John L. Chipperfield, P.Geol. 
	 	  	Senior Vice-President 
	 	  	15 /06 /2007 dd/mm/yr
  


Permit to Practice 

Sproule International Limited is a member of the Association of
Professional Engineers, Geologists and Geophysicists of Alberta and our permit
number is P6151. 








	Introduction —
      Page 7 


Certificate 

Jeff Duer, B.Sc., P.Eng. 

I, Jeff Duer, Reservoir Engineer at Sproule International
Limited, 900, 140 Fourth Ave SW, Calgary, Alberta, declare the following: 

	1. 	
      I hold the following degree:

		a. 	
      B.Sc., Chemical Engineering (2002), University of
      Calgary, Calgary AB, Canada

	 	 	 
	2. 	
      I am a registered professional:

		a. 	
      Professional Engineer (P.Eng.), Province of Alberta,
      Canada

	 	 	 
	3. 	
      I am a member of the following professional
      organizations:

		a. 	
      Association of Professional Engineers, Geologists and
      Geophysicists of Alberta (APEGGA)

		b. 	
      Petroleum Society of the Canadian Institute of Mining,
      Metallurgy and Petroleum (CIM)

		c. 	
      Society of Petroleum Engineers (SPE)

	 	 	 
	4. 	
      My contribution to the report entitled “Evaluation of the
      P&NG Reserves of TAG Oil Ltd.(As of March 31, 2007)” is based on my
      engineering knowledge and the data provided to me by the Company, from
      public sources, and from the non-confidential files of Sproule
      International Limited. I did not undertake a field inspection of the
      properties.

	 	 	 
	5. 	
      I have no interest, direct or indirect, nor do I expect
      to receive any interest, direct or indirect, in the properties described
      in the above-named report or in the securities of TAG Oil
  Ltd.




	 	Original signed by Jeff Duer 
	 	Jeff Duer, P.Eng. 









	Introduction —
      Page 8 


Certificate 

Douglas J. Carsted, B.Sc., P.Geol. 

I, Douglas J. Carsted, Vice-President, Geoscience, and Director
at Sproule International Limited, 900, 140 Fourth Ave SW, Calgary, Alberta,
declare the following: 

	1. 	
      I hold the following degrees:

		a. 	
      B.Sc. (Honours) Geology (1982) University of Manitoba,
      Winnipeg MB, Canada

		b. 	
      B.Sc. Chemistry (1979) University of Winnipeg, Winnipeg
      MB, Canada

	 	 	 
	2. 	
      I am a registered professional:

		a. 	
      Professional Geologist (P.Geol.) Province of Alberta,
      Canada

	 	 	 
	3. 	
      I am a member of the following professional
      organizations:

		a. 	
      Association of Professional Engineers, Geologists and
      Geophysicists of Alberta (APEGGA)

		b. 	
      Canadian Society of Petroleum Geologists (CSPG)

		c. 	
      American Association of Petroleum Geologists
  (AAPG)

		d. 	
      Petroleum Society of the Canadian Institute of Mining,
      Metallurgy and Petroleum (CIM)

		e. 	
      Canadian Well Logging Society (CWLS)

		f. 	
      Indonesian Petroleum Association, Professional Division
      (IPA)

	 	 	 
	4. 	
      I am a qualified evaluator and auditor as defined in
      National Instrument 51-101.

	 	 	 
	5. 	
      My contribution to the report entitled “Evaluation of the
      P&NG Reserves of TAG Oil Ltd.(As of March 31, 2007)” is based on my
      geological knowledge and the data provided to me by the Company, from
      public sources, and from the non-confidential files of Sproule
      International Limited. I did not undertake a field inspection of the
      properties.

	 	 	 
	6. 	
      I have no interest, direct or indirect, nor do I expect
      to receive any interest, direct or indirect, in the properties described
      in the above-named report or in the securities of TAG Oil
  Ltd.




	 	 
	 	Douglas J. Carsted, P.Geol.




 





	Introduction —
      Page 9 


Certificate 

Barrie F. Jose, M.Sc., P.Geoph. 

I, Barrie F. Jose, Manager, Geoscience, and Associate at
Sproule International Limited, 900, 140 Fourth Ave SW, Calgary, Alberta, declare
the following: 

	1. 	
      I hold the following degrees:

		a. 	
      M.Sc. Geophysics (1979) University of British Columbia,
      Vancouver BC, Canada

		b. 	
      B.Sc. (Honours) Geological Science with Physics (1977)
      Queens University, Kingston ON, Canada

	 	 	 
	2. 	
      I am a registered professional:

		a. 	
      Professional Geophysicist (P.Geoph.) Province of Alberta,
      Canada

	 	 	 
	3. 	
      I am a member of the following professional
      organizations:

		a. 	
      Association of Professional Engineers, Geologists and
      Geophysicists of Alberta

		
      (APEGGA )

		b. 	
      Canadian Society of Exploration Geophysicists
    (CSEG)

		c. 	
      Society of Exploration Geophysicists (SEG)

		d. 	
      Canadian Society of Petroleum Geologists (CSPG)

		e. 	
      American Association of Petroleum Geologists
  (AAPG)

		f. 	
      Petroleum Exploration Society of Great Britain
    (PESGB)

		g. 	
      European Association of Geoscientists and Engineers
      (EAGE)

	 	 	 
	4. 	
      I am a qualified evaluator and auditor as defined in
      National Instrument 51-101.

	 	 	 
	5. 	
      My contribution to the report entitled “Evaluation of the
      P&NG Reserves of TAG Oil Ltd.(As of March 31, 2007)” is based on my
      geophysical knowledge and the data provided to me by the Company, from
      public sources, and from the non-confidential files of Sproule
      International Limited. I did not undertake a field inspection of the
      properties.

	 	 	 
	6. 	
      I have no interest, direct or indirect, nor do I expect
      to receive any interest, direct or indirect, in the properties described
      in the above-named report or in the securities of TAG Oil
  Ltd.




	 	Original signed by Barrie F. Jose 
	 	Barrie F. Jose, P.Geoph. 



 





	Introduction —
      Page 10 


Certificate 

John L. Chipperfield, B.Sc., P.Geol. 

I, John L. Chipperfield, Senior Vice-President and Director of
Sproule Associates Limited, 900, 140 Fourth Ave SW, Calgary, Alberta, declare
the following: 

	1. 	
      I hold the following degree:

		a. 	
      B.Sc. (Honours) Geology (1972) University of Alberta,
      Edmonton AB, Canada

	 	 	 
	2. 	
      I am a registered professional:

		a. 	
      Professional Geologist (P.Geol.) Province of Alberta,
      Canada

	 	 	 
	3. 	
      I am a member of the following professional
      organizations:

		a. 	
      Association of Professional Engineers, Geologists and
      Geophysicists of Alberta (APEGGA)

		b. 	
      Canadian Society of Petroleum Geologists (CSPG)

		c. 	
      American Association of Petroleum Geologists
  (AAPG)

		d. 	
      Petroleum Society of the Canadian Institute of Mining,
      Metallurgy and Petroleum (CIM)

		e. 	
      Canadian Well Logging Society (CWLS)

		f. 	
      Ontario Petroleum Institute (OPI)

	 	 	 
	4. 	
      I am a qualified evaluator and auditor as defined in
      National Instrument 51-101.

	 	 	 
	5. 	
      My contribution to the report entitled “Evaluation of the
      P&NG Reserves of TAG Oil Ltd.(As of March 31, 2007)” is based on my
      geophysical knowledge and the data provided to me by the Company, from
      public sources, and from the non-confidential files of Sproule
      International Limited. I did not undertake a field inspection of the
      properties.

	 	 	 
	6. 	
      I have no interest, direct or indirect, nor do I expect
      to receive any interest, direct or indirect, in the properties described
      in the above-named report or in the securities of TAG Oil
  Ltd.




	 	 
	 	John L. Chipperfield, P.Geol.




 





	Summary — Page 1
    


Summary 

Table S-1, on the following page, summarizes our evaluation of
the P&NG reserves associated with the Company’s interest in the Cheal Field,
New Zealand. The Company has informed us that their tax pools exceed the
forecasted taxable income from the Cheal property and therefore, income taxes
have not been deducted in this report. The effective date of the evaluation is
March 31, 2007. A map showing the location of the Company’s Petroleum
Exploration Permit encompassing the Cheal property is included as Figure S-1.


The reserves were estimated deterministically for the proved,
proved plus probable, and proved plus probable plus possible reserves
categories. The oil reserves are presented in thousands of barrels, at stock
tank conditions. The pipeline gas reserves are presented in millions of cubic
feet, at base conditions of 14.65 psia and 60 degrees Fahrenheit.

The reserves definitions and ownership classification used in
this evaluation are in accordance with the standards defined by COGEH reserves
definitions and are consistent with NI 51-101. The net present values of the
reserves are presented in thousands of United States dollars, and are based on
annual projections of net revenue, which were discounted at various rates using
the mid-period discounting method. The price forecasts that formed the basis for
the revenue projections in the evaluation were based on Sproule’s March 31, 2007
pricing model. Table S-2 presents a summary of the forecasts used. Operating and
capital costs were escalated at 5 percent per for the first year, 4 percent the
second year, 3 percent the third year, and 2.0 percent per year thereafter as
set out in Table S-2. 

Well abandonment and disconnect costs were included in this
report for wells which have reserves assigned. No allowances for reclamation or
salvage values were made.

Summary forecasts of production and cash flow for the various
reserves categories are included as Tables S-3 through S-3D.

Figures S-2 through S-4 present the results of our evaluation
in graphical form. 


 





	2007/06/15
      13:59:30 TAGO.70414 SPROULE\LyndaV 


Table S-1 

	  Tag Oil
      Ltd.     
	Summary of the Evaluation of the Company's
      P&NG Reserves  
	 (As of March 31,
      2007)     
	  	Remaining Reserves 	Net Present Values 
	  	  	Company 	Before Income Taxes (M$) 
	  	Gross 	Gross 	Net 	At 0% 	At 5.0% 	At 10.0% 	At 15.0% 
	Light/Medium Oil
      (Mbbl) 	  	  	  	  	  	  	 
    
	Proved Undeveloped
    	1,477.0 	450.5 	397.9 	11,908 	10,312 	8,956 	7,795
    
	 
       Total Proved 	1,477.0 	450.5 	397.9 	11,908 	10,312 	8,956 	7,795 
	Probable Undeveloped
    	1,131.0 	345.0 	294.1 	12,820 	10,511 	8,721 	7,321
    
	 
       Total Probable 	1,131.0 	345.0 	294.1 	12,820 	10,511 	8,721 	7,321 
	Possible Undeveloped
    	1,030.0 	314.1 	265.4 	12,873 	9,388 	7,025 	5,391
    
	 
       Total Possible 	1,030.0 	314.1 	265.4 	12,873 	9,388 	7,025 	5,391 
	         Total 	3,638.0 	1,109.6 	957.4 	37,601 	30,211 	24,702 	20,508 
	Solution Gas (MMcf) - values included with lt/med oil -
    	  	  	  	  	 
    
	Proved Undeveloped
    	1,069 	326 	287 	  	  	  	 
    
	 
       Total Proved 	1,069 	326 	287 	  	  	  	 
    
	Probable Undeveloped
    	1,009 	308 	264 	  	  	  	 
    
	 
       Total Probable 	1,009 	308 	264 	  	  	  	 
    
	Possible Undeveloped
    	1,049 	320 	271 	  	  	  	 
    
	 
       Total Possible 	1,049 	320 	271 	  	  	  	 
    
	         Total 	3,127 	954 	822 	 
    	 
    	 
    	  
	GRAND TOTAL
      (Mboe) 	  	  	  	  	  	  	 
    
	Proved Undeveloped
    	1,655.1 	504.8 	445.7 	11,908 	10,312 	8,956 	7,795
    
	 
       Total Proved 	1,655.1 	504.8 	445.7 	11,908 	10,312 	8,956 	7,795 
	Probable Undeveloped
    	1,299.2 	396.3 	338.0 	12,820 	10,511 	8,721 	7,321
    
	 
       Total Probable 	1,299.2 	396.3 	338.0 	12,820 	10,511 	8,721 	7,321 
	Possible Undeveloped
    	1,204.9 	367.5 	310.7 	12,873 	9,388 	7,025 	5,391
    
	 
       Total Possible 	1,204.9 	367.5 	310.7 	12,873 	9,388 	7,025 	5,391 
	         Total 	4,159.2 	1,268.6 	1,094.4 	37,601 	30,211 	24,702 	20,508 









	Summary — Page 3
    



	Table S-2 
	           
       Summary of Selected Price Forecasts and Inflation Rate
      Assumptions 
	(Effective March 31, 2007) 
	  	  	  	  
	  	WTI Cushing a 	       Cheal 	  
	  	Oklahoma 	Natural Gas b 	Inflation Rate 
	               
                   Year 	($US/bbl) 	($US/Mcf) 	       (%/Yr) 
	  	  	  	  
	Historical
	  	  	 
    
	     
                   2000 	30.30 	  	       1.5 
	     
                   2001 	25.94 	  	       2.0 
	     
                   2002 	26.09 	  	       2.7 
	     
                   2003 	31.14 	  	       2.5 
	     
                   2004 	41.42 	  	       1.3 
	     
                   2005 	56.45 	  	       1.6 
	     
                   2006 	66.09 	  	       2.0 
	  	  	  	  
	Forecast 	  	  	  
	     
                   2007 	63.55 	     2.81 	       5.0 
	     
                   2008 	66.52 	     2.87 	       4.0 
	     
                   2009 	63.53 	     2.92 	       3.0 
	     
                   2010 	58.37 	     2.98 	       2.0 
	     
                   2011 	55.20 	     3.04 	       2.0 
	     
                   2012 	56.31 	     3.10 	       2.0 
	     
                   2013 	57.43 	     3.16 	       2.0 
	     
                   2014 	58.58 	     3.23 	       2.0 
	     
                   2015 	59.75 	     3.29 	       2.0 
	     
                   2016 	60.95 	     3.36 	       2.0 
	     
                   2017 	62.17 	     3.43 	       2.0 
	  	Escalation rate of 2.0% thereafter 	  


Notes: 

	a. 	
      40 degrees API, 0.4% sulphur.

	b. 	
      Incorporates a heating value of 1,150 btu per
  scf.




 





 





 





 





 





 





 





 





 





 





	Discussion - Page
      1 


Discussion 

	1.0 	General 


The Company’s reserves are located in the Cheal Field, New
Zealand. The field is located in the onshore portion of the Taranaki Basin,
which lies along the west coast of the North Island (Figure 1). The basin, which
contains Cretaceous to Recent sediments, covers an area of some 32,800 square
miles, most of which lies offshore.

The Company owns a 30.5% working interest in the shallow rights
of PEP 38738. The shallow rights include all strata from Recent to base of
Miocene, which encompasses the Intra Urenui and Mt. Messenger reservoirs in the
Cheal Field.

The Cheal structure has been penetrated by a total of seven
wells, Cheal-1, 2, A3X, A4, B1, B2 and B3. The three wells drilled from the
B-Pad location were drilled in the last year and represent new data that has
been incorporated into our evaluation. The new well log data has been useful in
re-evaluating the sandstones of the Mt. Messenger Formation. In addition, the
Company recently acquired a 45 km2 3D seismic survey that covers the
Cheal Field. The outline of the 3D seismic coverage is shown in blue in Figure
2, while the older 2D seismic coverage is shown in green. The acquisition of the
3D seismic has been a very positive development, as it has greatly clarified the
position of primary and secondary faults and the distribution of the horizons
within each fault block. 

	2.0 	Geophysics 


Data Control 

The Company provided a recently acquired 3D seismic program of
approximately 45 km2 shot over the Cheal Field in industry standard
SEGY format. This data was loaded into the Petrel 3D seismic and
geological visualization/interpretation software program. In addition, the
Company’s seismic horizon picks, interpreted fault sticks, well deviation
trajectories, available digital well logs and well tops were also loaded into
the 3D model (Figure 3). The Petrel software allows for the rapid
animation and review of 3D seismic volumes and the auditing of the picked
horizon and faults. 


 





	Discussion - Page
      2 


Following editing by Sproule, this data was used to build a 3D
structural model which was subsequently populated with petrophysical parameters
from Sproule’s petrophysical analysis to produce the 3D geological model used in
the volumetric calculations. 

Geophysical Interpretation 

The Company’s seismic horizon interpretation, as received by
Sproule, was picked on approximately every fifth inline and crossline over the
portion of the 3D survey that covers the main Cheal structure (Figure 3). In the
attached figures, the green arrow, shown in the lower left of the 3D perspective
views, always points northwards. From these horizon and fault picks, surfaces
were gridded and contoured to enable better initial viewing of the data. In
order to review the horizon and fault picks and associated surfaces in
comparison to the seismic reflections, the 3D seismic volume was animated in
both the inline and crossline directions. 

The fault sticks for each of the seven faults supplied by
Company were picked at inline, cross-line and time slices, respectively, by
Sproule in order to refine or re-interpret the fault sticks. This was necessary
to produce “cleaner” fault planes (Figure 5) to generate the 3D structural model
within Petrel (Figures 6 and 7). 

The main bounding fault on the western flank of the field is
intersected by a series of SSW-NNE trending splay faults in the vicinity of the
field (Figure 7). The magenta coloured fault in this figure can be seen to
separate the wells of the A Block (Cheal-1, 2, A3X and A4) from those of the B
Block (Cheal-B1, B2 and B3). 

A multi-layer depth conversion was conducted within
Petrel. Figure 8 shows the well tops and the depth structure at the Mt.
Messenger Sandstone #3. Depth structure maps on Sandstone #3 and Sandstone #2
are provided in Figures 9 and 10. 

	3.0 	Geology 


Cheal-1 was drilled in 1995 by New Zealand Oil & Gas
Services Ltd. Good oil and gas shows led to the testing of the Urenui Formation.
This formation was tested over a nine-day period at a steady rate of 48 bopd
with gas declining from 2.7 MMscfd to 1.05 MMscfd. The Mt. Messenger Formation
was not tested in this well, although shows and petrophysical analysis indicate
approximately 16 feet of net pay. The Urenui Formation was further tested for
1.2 days in December 2005 at 0.14 MMscfd of gas, with no oil reported.


 





	Discussion - Page
      3 


Cheal-2 was drilled in 1995 by New Zealand Oil & Gas
Services Ltd. as a step-out to Cheal-1. The well was tested over the Intra
Urenui Sandstone for a period of 6 days and flowed at initial rates of 1.8
MMscfd of gas with slugs of oil. The gas rates declined to 0.9 MMscfd with oil
rates of approximately 20 bopd. No water was produced during the test.
Petrophysical analysis indicates that the Mt. Messenger Sandstone is wet in this
well and defines the limits of the pool to the east. The Company plans to
convert this well to water disposal. 

The Company, as operator of a joint venture, drilled Cheal-A3X
in April 2004 to test the hydrocarbon potential of the Intra Urenui and Mt.
Messenger sandstones in an updip position from the Cheal-1 and Cheal-2 wells.
This well was directionally drilled from the Cheal “A” wellsite toward the NNE,
intersecting the Intra Urenui Sandstones between 4,603 and 4,737 feetMD and the
Mt. Messenger Sandstone between 5,800 and 5,863 feetMD. Good oil and gas shows
were noted over the two target intervals. The Mt. Messenger Sandstone produced a
total of 6,900 bbls of oil on test in June and July of 2004 and was then shut-in
until May 2005. The Mt. Messenger was further tested from May to August 2005, at
an average oil rate of 350 bopd with gas-oil ratios increasing from 475 to 825
scf per barrel. Water-cuts were less than one percent. 

The Company subsequently drilled Cheal-A4 in October 2004 to
further evaluate the hydrocarbon potential of the Intra Urenui and Mt. Messenger
sandstones. This well was directionally drilled from the Cheal “A” wellsite
toward the NE, intersecting the target horizons approximately halfway between
the Cheal A3X well and the downdip Cheal-2 well. The well was completed in the
uppermost Intra Urenui Formation and the Mt. Messenger Formation. The well was
tested from the Mt. Messenger Formation from November 2004 to May 2005 and from
September 2005 to December 2005. Over this period, oil production averaged 265
bopd with gas-oil ratios increasing from 500 to 730 scf per barrel. Water-cuts
had increased to 24 percent by December 2005. The Urenui was also tested in
April, May, October and November 2005 at gas rates of 0.1 to 1.1 MMscfd with
very little oil. 

During October and November 2006, the Company drilled three
deviated wells (Cheal-B1, B2 and B3) from the Cheal B Pad surface location,
approximately 0.8 miles to the north of the Cheal A Pad surface location. All
three wells intersected the Mt. Messenger sandstones north of the
northeast-southwest trending fault that transects the field. From petrophysical
analysis, Cheal B-1 and Cheal B-3 intersected the thicker and better quality Mt.
Messenger sandstones. Cheal B-2 encountered only about 6 feet of net pay in the
Mt. Messenger #3 sandstone, but did encounter 16 feet of net pay in the Mt.
Messenger #2 sandstone.

The oil-water contact established for the Mt. Messenger
Sandstone #3 in the A Pad wells is 4605 feet subsea (-1404m), while the B fault
block wells did not encounter an oil-water contact but established an ‘oil-down
to’ elevation of 4592 feet subsea (-1400m). There is the possibility 


 





	Discussion - Page
      4 


that the two fault block share the same oil-water contact but
that is yet to be established (Figure 9). For the oil-in-place volumetric
calculation for the B fault block, the ‘oil-down-to’ elevation was used to
define the proved oil volume and the elevation half way between the
‘oil-down-to’ elevation and the elevation of the oil-water contact in the A
fault block was used to calculate an additional probable oil-in-place volume.


For the Mt. Messenger Sandstone #2, which is the deeper
oil-bearing sand, an oil-water contact of 4625 feet subsea (-1410m) was
established (Figure 10). The oil-in-place volume calculated for this reservoir
has been classified as probable, because this reservoir has not been tested in
the B fault block, which contains the majority of the in-place oil volumes. 

Petrophysical Modelling 

The new well log data for the three B Pad wells was loaded into
the Prizm petrophysical analysis software package. The new data showed
that, in our previous evaluation, we had over-estimated the shale content of the
Mt. Messenger, which resulted in a lower average effective porosity value for
the field and, correspondingly, a higher average water saturation. Our new
estimate of average porosity is 23 percent, compared to our previous estimate of
18 percent. Similarly, as the porosity value increased, the corresponding
average water saturation decreased from an estimated 50 percent to 37 percent.
These values are considered reasonable, given the data available.

The well log data from the petrophysical evaluation was loaded
into Petrel and was up-scaled (Figure 11) and distributed within the 3D
geological model (Figure 12) for both porosity and water saturation. 

Net pay maps were generated from the 3D model and displayed as
2D maps in Figures 13 and 14 for the Mt. Messenger Sandstones #3 and #2,
respectively. These maps were then used to estimate the drainage areas for the
various proved, probable and possible portions of the reservoir. The location of
the Cheal B-4 well shown on Figure 13 is the projected intersection of the well
at the Mt. Messenger Sandstone #3 level, based on the well prognosis. As of
March 31, 2007, the well had not finished drilling. 


 





	Discussion - Page
      5 



	4.0 	Estimation of Reserves and Production
      Forecasts 


Oil reserves were estimated volumetrically for the Mt.
Messenger Formation using drainage areas assignments (Figures 13 and 14) and net
pay based on well logs and seismic interpretation. Reservoir porosity and water
saturation were obtained from well logs.

Proved undeveloped, probable and possible reserves were
assigned to the A3X, A4, A5, B1, B2, and B3 wells. As the costs for the site
work and development facilities are significant, the proved reserves assigned to
the A3X, A4, A5, B1, B2, and B3 wells were categorized as undeveloped. A3X and
A4 were produced one well at a time in test mode throughout 2004 -2006, with
combined cumulative production of 140,790 barrels of oil prior to March 31,
2007. The testing was done through rental equipment . All but two of the wells
are currently shut-in, waiting on site work and the installation of production
facilities. The B2 and B3 wells are currently producing to temporary testing
facilities and are expected to continue to produce until June at a combined rate
of 500 bopd. 

Commissioning of the A site should start in July, 2007, with
the A3 and A4 wells; however, the combined production will be limited to 600
bopd. The total production limit is expected to increase to 1000 bopd by
September, 2007, from the four producing wells plus the B1 well. The A5 and A6
wells are forecast to be drilled and on production in January, 2008, with an
increased total production limit of 1350 bopd. Upon drilling and completion of
the B5, B6, B7 wells, all of the wells will be put on production by July, 2008,
with an initial peak rate of 1900 bopd. 

Proved undeveloped, probable and possible reserves were
assigned to the three undrilled locations, A5, B6 and B7. Probable and possible
reserves were assigned to the two undrilled locations, A6 and B5.

Recovery factors were estimated to be 15 percent in the proved
(1P) case, 20 percent in the proved plus probable (2P) case and 25 percent in
the proved plus probable plus possible (3P) case. These recovery factors are
consistent with primary recoveries reported for the Ngatoro Field, which is the
offsetting analog field to Cheal. Water-flooding has not been considered in this
report. 

The solution gas reserves were estimated using gas-oil ratios
(GOR) of 700 scf per barrel, increasing to 1,500 scf per barrel. A surface loss
of 25 percent was included for fuel usage.


 





	Discussion - Page
      6 



	5.0 	Pricing 


Sproule’s short-term outlook for oil prices adopts the NYMEX
futures market for the forecast period ending December 31, 2009. The forecast
used in this evaluation was derived as of March 31, 2007 and reflects the
arithmetic average of the futures market at the close of trading each day, for
the month prior to the Termination of Trading date for a January contract. The
oil price forecasts are based on the NYMEX Division light, sweet (low-sulphur)
crude oil futures contract, which specifies the West Texas Intermediate crude as
a deliverable. 

In the long term, the price of oil will be governed by supply
and demand, and the degree that OPEC is able to manage supply will be a major
determinant in establishing oil prices for the next ten years. The long-term oil
price forecast, presented earlier as Table S-2, was based on a supply forecast
that falls in between a fully competitive market and a market controlled by an
effective OPEC production quota system. Price stability that promotes a steady
growth in demand is therefore in the best interest of the OPEC nations.
Sproule's long-term forecast for WTI has been capped at $51.00 per barrel (2007
dollars) in recognition of the economic hurdle rate of alternative supplies and
the increase in global demand for crude oil.

The oil price forecasts are based on a forecast of prices for
West Texas Intermediate crude at Cushing, Oklahoma. The price of this marker
crude is expected to directly reflect world oil prices over the forecast period.
The actual wellhead price of oil will vary with the quality of the crude and the
cost of the transportation from the wellhead to the trading hub. At Cheal a
positive differential of $US 4.00 per barrel was used.

The Company is expecting to receive a gas price of $NZ 3.30 per
gigajoule ($US 2.44 per MMbtu). The heating value for the solution gas was
estimated at 1,150 Btu per Scf, resulting in a gas price of $US 2.81 per Mcf.
This price is escalated two percent per year. 

	6.0 	Operating and Capital Costs
  


The Cheal A3X and A4 wells were produced one well at a time in
test mode through rental equipment. The wells are currently shut-in and the site
is to be reconstructed to allow production of these and future wells
simultaneously. Solution gas, which was previously flared as test production,
will be conserved during long-term production. 

The planned site facilities will be run off electricity
generated by an on-site generator using an engine fuelled by solution gas. Gas
sales are expected through the LTS pipeline to the west or the Waihapa treatment
station to the east. The Company also has a contract in place to export
electricity to the local power grid. In this evaluation, it was assumed that gas
used to provide 








	Discussion - Page
      7 


electricity to the local power grid would be equivalent in
value to selling the gas through the LTS pipeline or Waihapa treatment
station.

The wells will be produced through jet pumps. Hot water will be
circulated to address the waxing problem; however, it is expected that it will
be necessary to mobilize a crane to the site regularly to conduct deep wax cut
treatments by wireline.

With the previous rental equipment, it was not possible to use
condensate/pour point depressants as jet pump power fluid. The electric
centrifugal pumps to be installed in the reconstruction will be capable of
handling condensate / pour point depressants as the power fluid, which is
expected to reduce the need for deep wax cut treatments.

The oil/condensate /pour point depressant mix is expected to be
trucked to the Omata tank farm in New Plymouth. A trucking cost of $1.40 per
barrel and a processing fee of $US 0.20 – 0.78 per barrel were used, as outlined
in the table below. 

The capital costs used in the evaluation were based on
estimates prepared by the Company, and are summarized below. An exchange rate of
0.72 United States dollars per New Zealand dollar was used to convert the
capital budget information supplied by the Company. This rate was based on the
exchange rate for March 31, 2007, as obtained from the Bank of Canada website.


Capital Costs 
M$US (2007 Dollars) 


	
Item 
	Total 1P Case 
A3X, A4, A5, B1, 
B2,
      B3, B6, B7 	Total 2P Case 
A3X, A4, A5, A 6, B1,
      
B2, B3, B5, B6, B7 	Total 3P Case 
A3X, A4, A5, A 6, B1,
      
B2, B3, B5, B6, B7 
	Site Work and
      Facilities 	13,631 	13,631 	13,631 
	Workovers 	1,379 	1,379 	1,379 
	Gas Pipeline and
      Compression 	5,565 	5,565 	5,565 
	Drilling and
      Completion (Dec 07) 	2,173 	4,346 	4,346 
	Drilling and
      Completion (June 08) 	4,346 	6,519 	6,519 
	Total 	27,094 	31,440 	31,440 



Well abandonment and disconnect costs of US$ 216,000 per well
were used. No allowances for reclamation or salvage values were made.


 





	Discussion - Page
      8 


Operating costs were estimated as follows: 

Operating Costs 
(2007 Dollars) 


	
Dates 

	Operational Description 
Temporary
      production, 	
Fixed per well 
US$ / Month 
	
Variable oil 
US$ / bbl 
	
Variable gas 
US$ / bbl 
	
Trucking 
US$ / bbl 
	Marketing 
& sales 
US$ / bbl
    

	March 07 - June
      07 	2
      wells B2 and B3 	$134,661 	0.51
    	0.04
    	1.40
    	5.76
    
	July 07 - August
      07 	Commissioning A site 	$130,688 	0.42
    	0.04
    	1.40
    	5.76
    
	Sept 07 - Dec 07
    	Production Phase 1 	$38,280 	0.78
    	0.24
    	1.40
    	1.94
    
	Jan 08 - June 08
    	Production Phase 2 	$18,663 	0.60
    	0.14
    	1.40
    	1.94
    
	July 08 onward
    	Production Phase 3 	$15,595 	0.20
    	0.06
    	1.40
    	1.94
    



Operating and capital costs were escalated at 5 percent the
first year, 4 percent the second year, 3 percent the third year, and 2.0 percent
per year thereafter. 

	7.0 	Royalties and Taxes 


The Company has informed us that their tax pools exceed the
forecasted taxable income from the Cheal property; consequently, income taxes
have not been deducted in this report. 

The New Zealand royalty regime stipulates the payment of either
a 5 percent ad valorem royalty (AVR) or a 20 percent accounting profits royalty
(APR), whichever is the greater in any given year. 

The AVR is calculated at 5 percent of the net sales price
received.

The APR is a mechanism whereby the resource owner receives a
share of profits once all significant costs have been recovered by the producer.
It is payable on the net accumulated accounting profit of production from a
petroleum field. In calculating the accounting profit, 


 





	Discussion - Page
      9 


deductions are made and may include associated production
costs, capital costs (exploration costs, development costs, permit acquisition
costs and feasibility costs), indirect costs, abandonment costs, operating and
capital overhead allowance, operating costs and capital costs carried forward
and abandonment costs carried back. 

The APR royalty was calculated from our forecasts of cash flow
to take effect in the first quarter of 2009. 

	8.0 	Net Present Values 


The estimates of the P&NG reserves and their respective net
present values, summarized by reserves category, are presented in Tables 1 and
2. Detailed forecasts of production and cash flow are presented in Table 3. Well
abandonment and disconnect costs were included for wells which have reserves
assigned. No allowances for reclamation or salvage values were made.


 





	   Table
      1     
	   Cheal, New
      Zealand     
	 Volumetric Reservoir Data and Estimates of
      Reserves   
	   (As of March 31,
      2007)     
	

Pool/Location 
	Drainage 
Area 
(ac)
    	
Net Pay 
(ft) 	
Porosity 
(%) 	Water 
Saturation 
(%)
    	Oil 
FVF 
RB/STB 	Original Oil 
In Place
      
Mbbls 	Recovery 
Factor 
%
	Original 
Recoverable
      
Oil 
Mbbls 
	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  
	Mt. Messenger 3 	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  
	     Proved Undeveloped 	  	  	  	  	  	  	  	  
	             Cheal-A3X
      & A4 	162 	25 	23 	37 	1.22 	3722 	15 	558 
	           
       Cheal-B1, B2, & B3 	111 	35 	23 	37 	1.22 	3608 	15 	541 
	             Cheal-A5
	54 	25 	23 	37 	1.22 	1241 	15 	186 
	           
       Cheal-B6 & B7 	112 	21 	23 	37 	1.22 	2212 	15 	332 
	  	  	  	  	  	  	  	  	  
	     Proved + Probable 	  	  	  	  	  	  	  	  
	             Cheal-A3X
      & A4 	162 	25 	23 	37 	1.22 	3,722 	20 	744 
	           
       Cheal-B1, B2, & B3 	111 	35 	23 	37 	1.22 	3,608 	20 	722 
	             Cheal-B6
      & B7 	112 	21 	23 	37 	1.22 	2,212 	20 	442 
	           
       Cheal-A5 	54 	25 	23 	37 	1.22 	1,241 	20 	248 
	             Cheal-A6
	56 	15 	23 	37 	1.22 	762 	20 	152 
	           
       Cheal-B5 	53 	26 	23 	37 	1.22 	1,277 	20 	255 
	  	  	  	  	  	  	  	  	  
	     Proved +
      Probable + Possible 	  	  	  	  	  	  	  
	             Cheal-A3X
      & A4 	162 	25 	23 	37 	1.22 	3,722 	25 	931 
	           
       Cheal-B1, B2, & B3 	111 	35 	23 	37 	1.22 	3,608 	25 	902 
	             Cheal-B6
      & B7 	112 	21 	23 	37 	1.22 	2,212 	25 	553 
	           
       Cheal-A5 	54 	25 	23 	37 	1.22 	1,241 	25 	310 
	             Cheal-A6
	63 	14 	23 	37 	1.22 	762 	25 	191 
	           
       Cheal-B5 	114 	25 	23 	37 	1.22 	1,585 	25 	396 
	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  
	Mt. Messenger 2 	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  
	     Probable (No Proved
      Reserves for this zone) 	  	  	  	  	  	  
	           
       Cheal-SS2 compl. 	162 	8 	21 	46 	1.22 	922 	20 	184 
	  	  	  	  	  	  	  	  	  
	     Probable +
      Possible (No Proved Reserves for this zone) 	  	  	  	  	  
	             Cheal-SS2
      compl. 	356 	8 	21 	46 	1.22 	1,982 	25 	495 
	  	  	  	  	  	  	  	  	  
	Field Totals 	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  
	     Proved Undeveloped 	  	  	  	  	  	  	  	  
	           
       Total 	438 	27 	23 	37 	1.22 	10,783 	15 	1,617 
	  	  	  	  	  	  	  	  	  
	     Proved + Probable 	  	  	  	  	  	  	  	  
	             Total 	710 	22 	23 	38 	1.22 	13,745 	20 	2,749 
	  	  	  	  	  	  	  	  	  
	     Proved + Probable + Possible
    	  	  	  	  	  	  	  
	           
       Total 	971 	18 	23 	38 	1.22 	15,112 	25 	3,778 


 





	      Table
      2        
	      Cheal, New
      Zealand        
	    Estimates of Reserves
      and Net Present Values      
	      (As of
      March 31, 2007)        
	Oil Reserves 
	


Pool/Location 

	

Original
      
Oil In Place 

(Mbbls) 	

Recovery
      
Factor 

(%) 	
Original
      
Recoverable 
Oil 

(Mbbls) 	
Cumulative
      
Production to 
Dec. 31, 2006
      

(Mbbls) 	
Gross
      
Remaining Oil 
Reserves
      

(Mbbls) 	
Company
      
Working 
Interest 

(%)
	
Company
      
Gross 
Oil 
Reserves 
(Mbbls) 	
Lessor
      
Royalties 
and 
Burdens
      
(%) 	
Company 
Net
      
Oil 
Reserves 
(Mbbls) 	
Net Present Values
      
Before Taxes 

(M$US) 
	0% 	5% 	10% 	15% 	20% 
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Mt. Messenger 3 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Proved Undeveloped 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Cheal-A3X & A4 	3,722 	15.0 	558 	141 	418 	  	  	  	  	  	  	  	  	  
	 Cheal-B1, B2, & B3 	3,608 	15.0 	541 	  	541 	  	  	  	  	  	  	  	  	  
	         Cheal-A5
    	1,241 	15.0 	186 	  	186 	  	  	  	  	  	  	  	  	  
	Cheal-B6 & B7 	2,212 	15.0 	332 	  	332 	  	  	  	  	  	  	  	  	  
	Total Proved 	  	  	1,617 	141 	1,477 	30.5 	450 	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Probable 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	 Cheal-A3X & A4 	3,722 	5.0 	186 	  	186 	  	  	  	  	  	  	  	  	  
	 Cheal-B1, B2, & B3 	3,608 	5.0 	180 	  	180 	  	  	  	  	  	  	  	  	  
	Cheal-B6 & B7 	2,212 	5.0 	111 	  	111 	  	  	  	  	  	  	  	  	  
	         Cheal-A5
    	1,241 	5.0 	62 	  	62 	  	  	  	  	  	  	  	  	  
	         Cheal-A6 	762 	20.0 	152 	  	152 	  	  	  	  	  	  	  	  	  
	         
       Cheal-B5 	1,277 	20.0 	255 	  	255 	  	  	  	  	  	  	  	  	  
	 Total, Probable 	  	  	947 	  	947 	30.5 	289 	  	  	  	  	  	  	  
	Proved + Probable 	  	  	2,564 	141 	2,424 	30.5 	739 	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Possible 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	 Cheal-A3X & A4 	3,722 	5.0 	186 	  	186 	  	  	  	  	  	  	  	  	  
	 Cheal-B1, B2, & B3 	3,608 	5.0 	180 	  	180 	  	  	  	  	  	  	  	  	  
	 Cheal-B6 & B7 	2,212 	5.0 	111 	  	111 	  	  	  	  	  	  	  	  	  
	         Cheal-A5
    	1,241 	5.0 	62 	  	62 	  	  	  	  	  	  	  	  	  
	           Cheal-A6 	762 	5.0 	38 	  	38 	  	  	  	  	  	  	  	  	  
	         
       Cheal-B5 	1,585 	5.0 	141 	  	141 	  	  	  	  	  	  	  	  	  
	 Total, Possible 	  	  	719 	  	719 	30.5 	219 	  	  	  	  	  	  	  
	Proved + Probable +
      Possible 	  	3,283 	141 	3,142 	30.5 	958 	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Mt. Messenger 2 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Probable 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	 Cheal-SS2 compl. 	922 	20.0 	184 	  	184 	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Probable + Possible 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	 Cheal-SS2 compl. 	1,982 	25.0 	496 	  	496 	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Field Totals 	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Total Proved 	  	  	1,617 	141 	1,477 	30.5 	450 	AVR/APR 	  	11,908 	10,312 	8,956 	7,795 	6,795 
	  	  	  	  	  	  	  	  	  	  	12,820 	10,511 	8,721 	7,321 	5,272 
	Proved + Probable 	  	  	2,749 	141 	2,608 	30.5 	795 	AVR/APR 	  	24,728 	20,823 	17,677 	15,116 	13,007 
	  	  	  	  	  	  	  	  	  	  	  	  	  	  	  
	Proved + Probable + Possible 	  	3,778 	141 	3,638 	30.5 	1,109 	AVR/APR 	  	37,601 	31,211 	24,702 	20,508 	17,243 


 





	Table 2 cont'd 
	Cheal, New Zealand 
	Estimates of Reserves and Net Present
      Values 
	(As of March 31, 2007) 
	Gas Reserves 
	

Pool/Location 


	
Producing 
Gas Oil
      Ratio 
scf (sales) / bbl 	
Gross 
Remaining
      
Sales Gas 
Reserves 
(MMcf) 	

Company
      
Working 
Interest 
(%) 	
Company 
Gross
      
Sales Gas 
Reserves 
(MMcf) 	
Lessor 
Royalties
      
and 
Burdens 
(%) 	
Company 
Net
      
Sales Gas 
Reserves 
(MMcf) 	Net Present Values 
Before
      US Taxes 


(M$US) 
	0% 	           5% 	10% 	15% 	20% 
	  	  	  	  	  	  	  	  	  	  	  	  
	Mt. Messenger 2 & 3 	  	  	  	  	  	  	  	  	  	  	  
	  	  	  	  	  	  	  	  	  	  	  	  
	Proved Undeveloped 	  	  	  	  	  	  	  	  	  	  	  
	 Cheal-A3X & A4 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-B1, B2, & B3 	- Producing GOR of
      525 	  	  	  	  	  	  
	Cheal-A5 	increasing to 1,125 scf 	  	  	  	  	  	  
	Cheal-B6 & B7 	(sales) per barrel-
    	  	  	  	  	  	  
	Total Proved 	  	904 	30.5 	629 	AVR/APR 	547 	  	- Values are included with Oil
      Reserves - 
	  	  	  	  	  	  	  	  	  	  	  	  
	Probable 	  	  	  	  	  	  	  	  	  	  	  
	 Cheal-A3X & A4 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-B1, B2, & B3 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-B6 & B7 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-A5 	- Producing GOR of 525 	  	  	  	  	  	  	  	  
	  	increasing to 1,125
      scf 	  	  	  	  	  	  	  	  
	Cheal-A6 	(sales) per barrel- 	  	  	  	  	  	  	  	  
	Cheal-B5 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-SS2 compl. 	  	  	  	  	  	  	  	  	  	  	  
	 Total, Probable 	  	859 	30.5 	597 	AVR/APR 	510 	  	- Values are included
      with Oil Reserves - 
	  	  	  	  	  	  	  	  	  	  	  	  
	Proved + Probable 	  	1,763 	30.5 	1225 	AVR/APR 	1057 	  	- Values are included
      with Oil Reserves - 
	  	  	  	  	  	  	  	  	  	  	  	  
	Possible 	  	  	  	  	  	  	  	  	  	  	  
	 Cheal-A3X & A4 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-B1, B2, & B3 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-B6 & B7 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-A5 	- Producing GOR of
      525 	  	  	  	  	  	  	  	  
	  	increasing to 1,125 scf 	  	  	  	  	  	  	  	  
	Cheal-A6 	(sales) per barrel-
    	  	  	  	  	  	  	  	  
	Cheal-B5 	  	  	  	  	  	  	  	  	  	  	  
	Cheal-SS2 compl. 	  	  	  	  	  	  	  	  	  	  	  
	 Total, Possible 	  	943 	30.5 	656 	AVR/APR 	554 	  	- Values are included with Oil
      Reserves - 
	  	  	  	  	  	  	  	  	  	  	  	  
	Proved + Probable + Possible 	2,707 	30.5 	1,881 	AVR/APR 	1,612 	  	- Values are included with Oil
      Reserves - 


 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





	Constant Prices
      and Costs - Page 1 


Constant Prices and Costs 

Table C-1, presented on the following page, summarizes our
evaluation of the P&NG reserves of TAG Oil Ltd., as of March 31, 2007, based
on constant prices and costs. The values of the solution gas reserves have been
included in the values of the oil reserves.

Forecasts of cash flow for the constant price case are included
as Table C-2. 

The constant prices used in this specific evaluation are based
on the March 31, 2007 actual posted oil price for WTI, as determined by Sproule
International Limited, and the expected initial gas price for solution gas. The
constant prices used in this report are as follows: 

	 	Oil: West Texas Intermediate (WTI) 	$US 65.98 per barrel 
	 	 	 
	 	Natural Gas: 	$US 2.81 per Mcf 


Appropriate adjustments have been made to the constant crude
oil price in the forecasts of cash flow to account for quality and
transportation. The constant natural gas price quoted above has been adjusted
for heating value. 

The remaining assumptions relating to the calculation and
evaluation of the reserves in the constant case are the same as those presented
in the forecast prices and costs case. 

The values of the reserves presented in this constant price and
cost evaluation should not be taken out of context. They were prepared under the
guidelines of National Instrument 51-101 Constant Prices and Costs, and do not
reflect our opinion of the market value of these reserves. 


 





	2007/06/15
      15:55:26 TAGO.70414 SPROULE\LyndaV 


Table: C-1 

	  Tag Oil
      Ltd.     
	Summary of the Evaluation of the Company's
      P&NG Reserves  
	 (As of March 31,
      2007)     
	  	Remaining Reserves 	Net Present Values 
	  	  	Company 	Before Income Taxes (M$) 
	  	Gross 	Gross 	Net 	At 0% 	At 5.0% 	At 10.0% 	At 15.0% 
	Light/Medium Oil
      (Mbbl) 	  	  	  	  	  	  	 
    
	Proved Undeveloped
    	1,477.0 	450.5 	395.6 	13,661 	11,738 	10,136 	8,788
    
	 
       Total Proved 	1,477.0 	450.5 	395.6 	13,661 	11,738 	10,136 	8,788 
	Probable Undeveloped
    	1,131.0 	345.0 	291.4 	15,149 	12,203 	9,996 	8,310
    
	 
       Total Probable 	1,131.0 	345.0 	291.4 	15,149 	12,203 	9,996 	8,310 
	Possible Undeveloped
    	1,030.0 	314.1 	262.5 	14,969 	10,696 	7,908 	6,026
    
	 
       Total Possible 	1,030.0 	314.1 	262.5 	14,969 	10,696 	7,908 	6,026 
	         Total 	3,638.0 	1,109.6 	949.4 	43,779 	34,637 	28,040 	23,124 
	Solution Gas (MMcf) - values included with lt/med oil -
    	  	  	  	  	 
    
	Proved Undeveloped
    	1,069 	326 	285 	  	  	  	 
    
	 
       Total Proved 	1,069 	326 	285 	  	  	  	 
    
	Probable Undeveloped
    	1,009 	308 	261 	  	  	  	 
    
	 
       Total Probable 	1,009 	308 	261 	  	  	  	 
    
	Possible Undeveloped
    	1,049 	320 	268 	  	  	  	 
    
	 
       Total Possible 	1,049 	320 	268 	  	  	  	 
    
	         Total 	3,127 	954 	814 	 
    	 
    	 
    	  
	GRAND TOTAL
      (Mboe) 	  	  	  	  	  	  	 
    
	Proved Undeveloped
    	1,655.1 	504.8 	443.1 	13,661 	11,738 	10,136 	8,788
    
	 
       Total Proved 	1,655.1 	504.8 	443.1 	13,661 	11,738 	10,136 	8,788 
	Probable Undeveloped
    	1,299.2 	396.3 	334.8 	15,149 	12,203 	9,996 	8,310
    
	 
       Total Probable 	1,299.2 	396.3 	334.8 	15,149 	12,203 	9,996 	8,310 
	Possible Undeveloped
    	1,204.9 	367.5 	307.2 	14,969 	10,696 	7,908 	6,026
    
	 
       Total Possible 	1,204.9 	367.5 	307.2 	14,969 	10,696 	7,908 	6,026 
	         Total 	4,159.2 	1,268.6 	1,085.1 	43,779 	34,637 	28,040 	23,124 



 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





	National
      Instrument 51-101 


National Instrument 51-101 

This report was prepared for the purpose of evaluating the
Company’s P&NG reserves in accordance with Canadian Oil and Gas Evaluation
Handbook (COGEH) reserve definitions and standards, which is compliant with
National Instrument 51-101 (NI 51-101). In accordance with these standards, and
by reference in NI 51-101, certain tables are presented for both forecast and
constant prices and costs, which summarize the reserves and net present values,
as of March 31, 2007.

Form 51-101F2, which follows, presents a Report on Reserves
Data by Independent Qualified Reserves Evaluator or Auditor.

Forecast Prices and Costs 

Table 1 presents a summary of reserves for the various reserves
categories. Table 2 presents a summary of net present values of future net
revenue. Table 3 presents the total future net revenue (undiscounted) for the
total proved (1P), total proved plus probable (2P) and total proved plus
probable plus possible (3P) reserves categories. Table 4 presents the net
present value, discounted at 10 percent per year, of future net revenue by
production group for the 1P, 2P and 3P reserves categories. Table 5 presents a
summary of pricing and inflation rate assumptions. 

Constant Prices and Costs 

Constant Prices and Costs are defined in National Instrument
51-101 as the reporting issuer’s prices and costs as at the evaluation effective
date. The reporting issuer’s prices and costs are defined as the actual posted
price for oil, natural gas and natural gas by-products, after historical
adjustments for transportation, gravity and other factors. 

Table 6 presents a summary of reserves for the various reserves
categories. Table 7 presents a summary of net present values of future net
revenue. Table 8 presents the total future net revenue (undiscounted) for the
total proved and total proved plus probable reserves categories. Table 9
presents the net present value, discounted at 10 percent per year, of future net
revenue by production group for the total proved and total proved plus probable
reserves categories. Table 10 presents the summary of pricing assumptions for
constant prices and costs. 


 




Form 51-101F2 

Report on Reserves Data 
by Independent Qualified Reserves
Evaluator or Auditor 

Report on Reserves Data 

To the Board of Directors of TAG Oil Ltd. (the “Company”): 

	1. 	
      We have evaluated the Company’s Reserves Data as at March
      31, 2007. The reserves data consist of the following: 

	  	  	  	  
	  	(a) 	(i) 	
      proved, proved plus probable, and proved plus probable
      plus possible oil and solution gas reserves estimated as at March 31, 2007
      using forecast prices and costs; and 

	  	  	  	
	  	  	(ii) 	
      the related estimated future net revenue; and 

	  	  	  	
       

	  	(b) 	(i) 	
      proved oil and solution gas reserves quantities were
      estimated as at March 31, 2007 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). 

	  	
	  	
	  	







	TAG Oil Ltd. 	- 2 -
    
	Sproule International Limited 	  



	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.

	 	 
	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 March 31, 2007, 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:




	 	  	  	  	Net Present Value of Future Net
      Revenue 
	 	Independent
    	  	  	(10% Discount Rate) 
	 	Qualified
    	  	Location 	  	  	  	  
	 	Reserves
	Description 	of 	  	  	  	  
	 	Evaluator
      or 	and Preparation Date of 	Reserves 	Audited 	Evaluated 	Reviewed 	Total 
	 	Auditor 	Evaluation Report 	(Country) 	(M$US) 	(M$US) 	(M$US) 	(M$US) 
	 	Sproule 	Evaluation of the P&NG 	New 	  	17,677 	  	17,677 
	 	  	Reserves of 	Zealand 	  	  	  	 
    
	 	  	TAG OIL LTD as of 	  	  	  	  	 
    
	 	  	March 31, 2007, 	  	  	  	  	 
    
	 	  	prepared May to June 	  	  	  	  	 
    
	 	  	2007 	  	  	  	  	 
    
	 	Total 	 
    	 
    	Nil 	17,677 	Nil 	17,677 



	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 judgments
      regarding future events, actual results will vary and the variations may
      be material.








	TAG Oil Ltd. 	- 3 -
    
	Sproule International Limited 	  


Executed as to our report referred to above: 

	Sproule International Limited 
	Calgary, Alberta 
	June 15,
      2007 



	 	 	 Original signed by Jeff Duer 
	 	 	Jeff Duer, P.Eng. 
	 	 	Reservoir Engineer 
	 	 	 
	 	 	 
	 	 	 
	 	 	Original signed by Michael W. Maughan, C.P.G., P.Geol.
    
	 	    for 	Douglas J. Carsted, P.Geol. 
	 	 	Vice-President, Geoscience 
	 	 	 
	 	 	 
	 	 	 
	 	 	 
	 	 	Original signed by Barrie F. Jose 
	 	 	Barrie F. Jose, P.Geoph. 
	 	 	Manager, Geoscience 
	 	 	 
	 	 	 
	 	 	 
	 	 	 
	 	 	Original signed by Robert N. Johnson, P.Eng. 
	 	 for	 John L. Chipperfield, P.Geol. 
	 	 	Senior Vice-President 







	2007/06/15
      14:09:25 - 70414 	National Instrument 51-101 



	    Table
      1       
	   NI
      51-101      
	 Summary of Oil and Gas
      Reserves    
	  as of March 31,
      2007      
	  Forecast Prices and
      Costs     
	Reserves 
	  	 	 	 	 	 
	  	 	 	Natural Gas 	 	 
	  	Light and Medium 	 	(non-associated & 	 	 
	  	Oil 	     Heavy Oil 	associated) 	Coalbed Methane 	Natural Gas Liquids 
	Reserve
      Category 	Gross 	Net 	Gross 	Net 	Gross 	Net 	Gross 	Net 	Gross 	Net 
	  	(Mbbl) 	(Mbbl) 	(Mbbl) 	(Mbbl) 	(MMcf)   	(MMcf) 	(MMcf) 	(MMcf) 	(Mbbl) 	(Mbbl) 
	Proved 	  	  	  	  	  	  	  	  	  	 
    
	Developed Producing
    	0 	0 	         0 	             
       0 	0 	0 	0 	0 	0 	0

	Developed
      Non-Producing 	0 	0 	         0 	             
       0 	0 	0 	0 	0 	0 	0

	Undeveloped 	450 	398 	           0 	             
         0 	326 	287 	0 	0 	0 	0

	Total Proved
    	450 	398 	         
       0 	             
         0 	326 	287 	0 	0 	0 	0 
	Probable 	345 	294 	           0 	             
         0 	308 	264 	0 	0 	0 	0

	Total Proved
      Plus 	795 	692 	         
       0 	             
         0 	634 	551 	0 	0 	0 	0 
	Probable 	  	  	  	  	  	  	  	  	  	 
    
	Possible 	314 	265 	           0 	             
       0 	320 	271 	0 	0 	0 	0

	Total Proved
      Plus 	1,110 	957 	         
       0 	             
         0 	954 	822 	0 	0 	0 	0 
	Probable Plus Possible 	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	  


Reference: Item 2.2(1) of Form 51-101F1 





	2007/06/15
      14:09:25 - 70414 	National Instrument 51-101 



	   Table
      2       
	   NI
      51-101       
	 Summary of Net Present Values
      of     
	   Future Net
      Revenue      
	   as of March 31,
      2007      
	  Forecast Prices and
      Costs     
	  	Net Present Values of Future Net
      Revenue 
	  	 	 
	  	Before Income Taxes 	After Income Taxes 
	  	Discounted at (%/Year) 	Discounted at (%/Year) 
	Reserves
      Category 	0 	5 	10 	15 	20 	0 	5 	10 	15 	20 
	  	(M$) 	(M$) 	       (M$) 	 (M$) 	 (M$) 	(M$) 	(M$) 	(M$) 	(M$) 	 (M$) 
	Proved 	  	  	  	  	  	  	  	  	  	 
    
	Developed Producing
    	0 	0 	0 	0 	0 	0 	0 	0 	0 	0
  
	Developed
      Non-Producing 	0 	0 	0 	0 	0 	0 	0 	0 	0 	0
  
	Undeveloped 	11,908 	10,312 	8,956 	7,795 	6,795 	11,908 	10,312 	8,956 	7,795 	6,795
    
	Total Proved
    	11,908 	10,312 	8,956 	7,795 	6,795 	11,908 	10,312 	8,956 	7,795 	6,795 
	Probable 	12,820 	10,511 	8,721 	7,321 	6,212 	12,820 	10,511 	8,721 	7,321 	6,212
    
	Total Proved +
      Probable 	24,728 	20,823 	17,677 	15,116 	13,007 	24,728 	20,823 	17,677 	15,116 	13,007 
	Possible 	12,873 	9,388 	7,025 	5,391 	4,236 	12,873 	9,388 	7,025 	5,391 	4,236
    
	Total Proved +
      Probable 	37,601 	30,211 	24,702 	20,508 	17,243 	37,601 	30,211 	24,702 	20,508 	17,243 
	+ Possible 	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	  



	Reference Item 2.2(2) of Form 51-101F1 
	 
	Notes: 



	
      	

	
      NPV of FNR include all resource income:

		
      	

	
      Sale of oil, gas, by-product reserves

		
      	

	
      Processing third party reserves

		
      	

	
      Other income

	
      	

	
      Income Taxes

		
      	

	
      Includes all resource income

		
      	

	
      Apply appropriate income tax calculations

		
      	

	
      Include prior tax pools








	2007/06/15
      14:09:25 - 70414 	National Instrument 51-101 



	   Table
      3     
	   NI
      51-101     
	  Total Future Net
      Revenue    
	   Undiscounted    
  
	  as of March 31,
      2007    
	  Forecast Prices and
      Costs    
	  	  	  	  	  	  	Future 	  	Future 
	  	  	  	  	  	  	Net 	  	Net 
	  	  	  	  	  	Well 	Revenue 	  	Revenue 
	  	  	  	Opera- 	Develop- 	Abandon- 	Before 	  	After 
	  	  	  	ting 	ment 	ment / 	Income 	Income 	Income 
	Reserves
      Category 	Revenue 	Royalties 	Costs 	Costs 	Other 	Taxes 	Taxes 	Taxes 
	  	(M$) 	   (M$) 	(M$) 	(M$) 	Costs 	(M$) 	(M$) 	(M$) 
	  	  	  	  	  	(M$) 	  	  	  
	  	  	  	  	  	  	  	  	  
	Proved 	30,900 	3,584 	6,436 	8,330 	642 	     11,908 	0 	 
         11,908 
	  	  	  	  	  	  	  	  	  
	Proved Plus Probable 	53,978 	6,947
    	 
       11,746 	9,689
    	868
    	 
         24,728 	0 	     24,728 
	  	  	  	  	  	  	  	  	  
	Proved + Prob. + Poss. 	75,627 	10,235 	 
       17,143 	9,689
    	959
    	 
         37,601 	0 	     37,601 


Reference Item 2.2(3)(b) of Form 51-101F1 





	2007/06/15
      14:09:25 - 70414 	National Instrument 51-101 



	 Table 4  
	 NI 51-101  
	 Net Present Value of Future Net
      Revenue  
	 by Production Group  
	 as of March 31, 2007  
	 Forecast Prices and Costs  
	  	  	Future Net Revenue 
	  	  	Before Income Taxes 
	Reserves
      Category 	   Production Group 	(Discounted at 
	  	  	10%/Year) 
	  	  	(M$) 
	Proved 	Light and Medium Crude Oil (including solution
      gas and associated by-products) 	8,956
    
	  	Heavy Oil (including solution gas and
      associated by-products) 	0
  
	  	Natural Gas (including associated by-products)
    	0
  
	  	Coalbed Methane (including associated by-products) 	0 
	  	  	  
	Proved Plus 	  	 
    
	Probable 	Light and Medium Crude Oil (including solution
      gas and associated by-products) 	17,677
    
	  	Heavy Oil (including solution gas and
      associated by-products) 	0
  
	  	Natural Gas (including associated by-products)
    	0
  
	  	Coalbed Methane (including associated by-products) 	0 
	  	  	  
	Proved Plus 	  	 
    
	Probable Plus 	Light and Medium Crude Oil (including solution
      gas and associated by-products) 	24,702
    
	Possible 	Heavy Oil (including solution gas and
      associated by-products) 	0
  
	  	Natural Gas (including associated by-products)
    	0
  
	  	Coalbed Methane (including associated by-products) 	0 


Reference Item 2.1(3)(c) of Form 51-101F1 





	National
      Instrument 51-101 



	Table 5 
	NI 51-101 
	Summary of Pricing and 
	Inflation Rates Assumptions 
	as of March 31, 2007 
	Forecast Prices and Costs 
	  	  	  	  
	  	WTI Cushing 	Cheal 	  
	  	Oklahoma 	Natural Gas 	Inflation Rate1 
	Year 	($US/bbl) 	($US/Mcf) 	(%/Yr) 
	  	  	  	  
	Historical
	  	  	 
    
	     
                   2000 	30.30 	  	1.5
    
	     
                   2001 	25.94 	  	2.0
    
	     
                   2002 	26.09 	  	2.7
    
	     
                   2003 	31.14 	  	2.5
    
	     
                   2004 	41.42 	  	1.3
    
	     
                   2005 	56.46 	  	1.6
    
	     
                   2006 	66.09 	  	2.0
    
	  	  	  	  
	Forecast 	  	  	  
	     
                   2007 	63.55 	2.81 	5.0
    
	     
                   2008 	66.52 	2.87 	4.0
    
	     
                   2009 	63.53 	2.92 	3.0
    
	     
                   2010 	58.37 	2.98 	2.0
    
	     
                   2011 	55.20 	3.04 	2.0
    
	     
                   2012 	56.31 	3.10 	2.0
    
	     
                   2013 	57.43 	3.16 	2.0
    
	     
                   2014 	58.58 	3.23 	2.0
    
	     
                   2015 	59.75 	3.29 	2.0
    
	     
                   2016 	60.95 	3.36 	2.0
    
	     
                   2017 	62.17 	3.43 	2.0
    
	  	Escalation rate of 2.0% thereafter 	  


(1) Inflation rates for forecasting prices and costs. 

Notes: 
This summary table identifies benchmark
reference oil pricing schedules that might apply to a reporting issuer.

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


 





	2007/06/15
      15:58:11 - 70414 	National Instrument 51-101 



	    Table
      6       
	   NI
      51-101      
	 Summary of Oil and Gas
      Reserves    
	  as of March 31,
      2007      
	  Constant Prices and
      Costs     
	Reserves 
	  	 	 	 	 	 
	  	 	 	Natural Gas 	 	 
	  	Light and Medium 	 	(non-associated & 	 	 
	  	Oil 	     Heavy Oil 	associated) 	Coalbed Methane 	Natural Gas Liquids 
	Reserve
      Category 	Gross 	Net 	Gross 	Net 	Gross 	Net 	Gross 	Net 	Gross 	Net 
	  	(Mbbl) 	(Mbbl) 	(Mbbl) 	(Mbbl) 	(MMcf)   	(MMcf) 	(MMcf) 	(MMcf) 	(Mbbl) 	(Mbbl) 
	Proved 	  	  	  	  	  	  	  	  	  	 
    
	Developed Producing
    	0 	0 	         0 	           
         0 	0 	0 	0 	0 	0 	0
  
	Developed
      Non-Producing 	0 	0 	         0 	           
         0 	0 	0 	0 	0 	0 	0
  
	Undeveloped 	450 	396 	           0 	           
           0 	326 	285 	0 	0 	0 	0
  
	Total Proved
    	450 	396 	         
       0 	           
           0 	326 	285 	0 	0 	0 	0 
	Probable 	345 	291 	           0 	           
           0 	308 	261 	0 	0 	0 	0
  
	Total Proved
      Plus 	795 	687 	         
       0 	           
           0 	634 	546 	0 	0 	0 	0 
	Probable 	  	  	  	  	  	  	  	  	  	 
    
	Possible 	314 	262 	           0 	           
         0 	320 	268 	0 	0 	0 	0
  
	Total Proved
      Plus 	1,110 	949 	         
       0 	           
           0 	954 	814 	0 	0 	0 	0 
	Probable Plus Possible 	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	  


Reference: Item 2.2(1) of Form 51-101F1 





	2007/06/15
      15:58:11 - 70414 	National Instrument 51-101 



	   Table
      7       
	   NI
      51-101       
	 Summary of Net Present Values
      of     
	   Future Net
      Revenue      
	   as of March 31,
      2007      
	  Constant Prices and
      Costs     
	  	Net Present Values of Future Net
      Revenue 
	  	 	 
	  	Before Income Taxes 	After Income Taxes 
	  	Discounted at (%/Year) 	Discounted at (%/Year) 
	Reserves
      Category 	0 	5 	10 	15 	20 	0 	5 	10 	15 	20 
	  	(M$) 	(M$) 	       (M$) 	 (M$) 	 (M$) 	(M$) 	(M$) 	(M$) 	(M$) 	 (M$) 
	Proved 	  	  	  	  	  	  	  	  	  	 
    
	Developed Producing
    	0 	0 	0 	0 	0 	0 	0 	0 	0 	0
  
	Developed
      Non-Producing 	0 	0 	0 	0 	0 	0 	0 	0 	0 	0
  
	Undeveloped 	13,661 	11,738 	10,136 	8,788 	7,641 	13,661 	11,738 	10,136 	8,788 	7,641
    
	Total Proved
    	13,661 	11,738 	10,136 	8,788 	7,641 	13,661 	11,738 	10,136 	8,788 	7,641 
	Probable 	15,149 	12,203 	9,996 	8,310 	6,999 	15,149 	12,203 	9,996 	8,310 	6,999
    
	Total Proved +
      Probable 	28,810 	23,941 	20,132 	17,098 	14,640 	28,810 	23,941 	20,132 	17,098 	14,640 
	Possible 	14,969 	10,696 	7,908 	6,026 	4,715 	14,969 	10,696 	7,908 	6,026 	4,715
    
	Total Proved +
      Probable 	43,779 	34,637 	28,040 	23,124 	19,355 	43,779 	34,637 	28,040 	23,124 	19,355 
	+ Possible 	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	 
    	  


Reference Item 2.2(2) of Form 51-101F1 

Notes: 

	
      	

	
      NPV of FNR includeS all resource income:

		
      	

	
      Sale of oil, gas, by-product reserves

		
      	

	
      Processing third party reserves

		
      	

	
      Other income

	
      	

	
      Income Taxes

		
      	

	
      Includes all resource income

		
      	

	
      Apply appropriate income tax calculations

		
      	

	
      Include prior tax pools








	2007/06/15
      15:58:11 - 70414 	National Instrument 51-101 



	   Table
      8     
	   NI
      51-101     
	  Total Future Net
      Revenue    
	   Undiscounted    
  
	  as of March 31,
      2007    
	  Constant Prices and
      Costs    
	  	  	  	  	  	  	Future 	  	Future 
	  	  	  	  	  	  	Net 	  	Net 
	  	  	  	  	  	Well 	Revenue 	  	Revenue 
	  	  	  	Opera- 	Develop- 	Abandon- 	Before 	  	After 
	  	  	  	ting 	ment 	ment / 	Income 	Income 	Income 
	Reserves Category 	Revenue 	Royalties 	Costs 	Costs 	Other 	Taxes 	Taxes 	Taxes 
	  	(M$) 	   (M$) 	(M$) 	(M$) 	Costs 	(M$) 	(M$) 	(M$) 
	  	 
    	  	  	 
    	(M$) 	 
    	  	  
	  	  	  	  	  	  	  	  	  
	Proved 	32,235 	3,931 	5,853 	8,264 	527 	     13,661 	0 	 
         13,661 
	  	  	  	  	  	  	  	  	  
	Proved Plus Probable 	57,047 	7,783
    	 
       10,205 	9,589
    	659
    	 
         28,810 	0 	     28,810 
	  	  	  	  	  	  	  	  	  
	Proved + Prob. + Poss. 	79,728 	11,512 	 
       14,190 	9,589
    	659
    	 
         43,779 	0 	     43,779 


Reference Item 2.2(3)(b) of Form 51-101F1 





	2007/07/19
      11:06:38 - 70414 	National Instrument 51-101 



	 Table 9  
	 NI 51-101  
	 Net Present Value of Future Net
      Revenue  
	 by Production Group  
	 as of March 31, 2007  
	 Constant Prices and Costs  
	  	  	Future Net Revenue 
	  	  	Before Income Taxes 
	Reserves Category 	Production Group 	(Discounted at 
	  	  	10%/Year) 
	  	  	(M$) 
	Proved
    	Light and Medium Crude Oil (including solution
      gas and associated by-products) 	10,136 
	 
    	Heavy Oil (including solution gas and
      associated by-products) 	0 
	 
    	Natural Gas (including associated by-products)
    	0 
	  	Coalbed Methane (including associated by-products) 	0 
	  	  	  
	Proved
      Plus 	  	  
	Probable 	Light and Medium Crude Oil (including solution
      gas and associated by-products) 	20,132 
	 
    	Heavy Oil (including solution gas and
      associated by-products) 	0 
	 
    	Natural Gas (including associated by-products)
    	0 
	  	Coalbed Methane (including associated by-products) 	0 
	  	  	  
	Proved
      Plus 	  	  
	Probable Plus 	Light and Medium Crude Oil (including solution
      gas and associated by-products) 	28,040 
	Possible 	Heavy Oil (including solution gas and
      associated by-products) 	0 
	 
    	Natural Gas (including associated by-products)
    	0 
	  	Coalbed Methane (including associated by-products) 	0 


Reference Item 2.1(3)(c) of Form 51-101F1 





	National
      Instrument 51-101 



	Table 10 
	NI 51-101 
	Summary of Pricing Assumptions 
	as of March 31, 2007 
	Constant Prices and Costs 
	 	Oil 	Natural Gas 
	 	WTI  	 
	 	    Cushing  	 
	Year 	Oklahoma 	Cheal 
	 	($US/bbl) 	($US/Mcf) 
	 	  	  
	Historical
	  	 
    
	Dec. 31, 2001 	26.83 	 
    
	Dec. 31, 2002 	19.78 	 
    
	Dec. 31, 2003 	31.23 	  
	Dec. 31, 2004 	32.56 	  
	Dec. 31, 2005 	44.04 	  
	Dec. 31, 2006 	61.05 	             2.90 
	 	  	  
	Forecast 	  	  
	March. 31, 2007 	65.89 	           
       2.81 


Notes: 
This summary table identifies benchmark
reference oil pricing schedules that might apply to a reporting issuer.

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








	  CHEAL,
      NZ     
	Summary of the Evaluation of the Company's
      P&NG Reserves  
	 (As of March 31,
      2007)     
	  	Remaining Reserves 	Net Present Values 
	  	  	Company 	Before Income Taxes (M$) 
	  	Gross 	Gross 	Net 	At 0% 	At 5.0% 	At 10.0% 	At 15.0% 
	Light/Medium Oil
      (Mbbl) 	  	  	  	  	  	  	 
    
	Proved Undeveloped
    	1,477.0 	450.5 	397.9 	11,908 	10,312 	8,956 	7,795
    
	 
       Total Proved 	1,477.0 	450.5 	397.9 	11,908 	10,312 	8,956 	7,795 
	Probable Undeveloped
    	1,131.0 	345.0 	294.1 	12,820 	10,511 	8,721 	7,321
    
	 
       Total Probable 	1,131.0 	345.0 	294.1 	12,820 	10,511 	8,721 	7,321 
	Possible Undeveloped
    	1,030.0 	314.1 	265.4 	12,873 	9,388 	7,025 	5,391
    
	 
       Total Possible 	1,030.0 	314.1 	265.4 	12,873 	9,388 	7,025 	5,391 
	         Total 	3,638.0 	1,109.6 	957.4 	37,601 	30,211 	24,702 	20,508 
	Solution Gas (MMcf) - values included with lt/med oil -
    	  	  	  	  	 
    
	Proved Undeveloped
    	1,069 	326 	287 	  	  	  	 
    
	 
       Total Proved 	1,069 	326 	287 	  	  	  	 
    
	Probable Undeveloped
    	1,009 	308 	264 	  	  	  	 
    
	 
       Total Probable 	1,009 	308 	264 	  	  	  	 
    
	Possible Undeveloped
    	1,049 	320 	271 	  	  	  	 
    
	 
       Total Possible 	1,049 	320 	271 	  	  	  	 
    
	         Total 	3,127 	954 	822 	 
    	 
    	 
    	  
	GRAND TOTAL
      (Mboe) 	  	  	  	  	  	  	 
    
	Proved Undeveloped
    	1,655.1 	504.8 	445.7 	11,908 	10,312 	8,956 	7,795
    
	 
       Total Proved 	1,655.1 	504.8 	445.7 	11,908 	10,312 	8,956 	7,795 
	Probable Undeveloped
    	1,299.2 	396.3 	338.0 	12,820 	10,511 	8,721 	7,321
    
	 
       Total Probable 	1,299.2 	396.3 	338.0 	12,820 	10,511 	8,721 	7,321 
	Possible Undeveloped
    	1,204.9 	367.5 	310.7 	12,873 	9,388 	7,025 	5,391
    
	 
       Total Possible 	1,204.9 	367.5 	310.7 	12,873 	9,388 	7,025 	5,391 
	         Total 	4,159.2 	1,268.6 	1,094.4 	37,601 	30,211 	24,702 	20,508 


ESCALATED CASE: Using NZ pricing at Mar 31, 2007.





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





 





	Appendix A — Page
      1 


Appendix A — Definitions 

The following definitions form the basis of our classification
of reserves and values presented in this report. They have been prepared by the
Standing Committee on Reserves Definitions of the Petroleum Society of the CIM
(“CIM”), incorporated in the Society of Petroleum Evaluation Engineers (“SPEE”)
Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”) and specified by
National Instrument 51-101 (“NI 51-101”). 

Reserves are estimated remaining quantities of oil and natural
gas and related substances anticipated to be recoverable from known
accumulations, from a given date forward, based on: 

	analysis of drilling, geological, geophysical and engineering data;
  
	the use of established technology;
  
	specified economic conditions, which are generally accepted as being
  reasonable, and shall be disclosed; and
  
	a remaining reserve life of 50 years. 


Reserves are classified according to the degree of certainty
associated with the estimates. 

	1. 	
      Proved Reserves

	 	 
		
      Proved reserves are those 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.

	 	 
	2. 	
      Probable Reserves

	 	 
		
      Probable reserves are those additional reserves that are
      less certain to be recovered than proved reserves. 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.

	 	 
	3. 	 Possible Reserves

	 	 
		
      Possible reserves are those additional reserves that are
      less certain to be recovered than probable reserves. It is unlikely that
      the actual remaining quantities recovered will exceed the sum of the
      estimated proved plus probable plus possible
reserves.



 



   





	Appendix A — Page
      2 


Other criteria that must also be met for the categorization of
reserves are provided in Section 5.5 of the COGE Handbook. 

Each of the reserves categories (proved, probable, and
possible) may be divided into developed or undeveloped categories. 

	4. 	
      Developed Reserves

	 	 
		
      Developed reserves are those 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. The developed category may be subdivided into producing and
      non-producing.

	 	 
	5. 	
      Developed Producing Reserves

	 	 
		
      Developed producing reserves are those reserves that are
      expected to be recovered from completion intervals open at the time of the
      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.

	 	 
	6. 	
      Developed Non-Producing Reserves

	 	 
		
      Developed non-producing reserves are those 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.

	 	 
	7. 	
      Undeveloped Reserves

	 	 
		
      Undeveloped reserves are those reserves expected to be
      recovered from known accumulations where a significant expenditure (e.g.,
      when compared to the cost of drilling a well) is required to render them
      capable of production. They must fully meet the requirements of the
      reserves classification (proved, probable, possible) to which they are
      assigned.

	 	 
		
      In multi-well pools, it may be appropriate to allocate
      total pool reserves between the developed and undeveloped categories or to
      subdivide the developed reserves for the pool between developed producing
      and developed non-producing. This allocation should be based on the
      estimator’s assessment as to the reserves that will be recovered from
      specific wells, facilities, and completion intervals in the pool and their
      respective development and production status.




 





	Appendix A — Page
      3 



	8. 	
      Levels of Certainty for Reported
Reserves

	 	 	 
		
      The qualitative certainty levels contained in the
      definitions in Sections 1, 2 and 3 are applicable to individual reserves
      entities, which refers to the lowest level at which reserves estimates are
      made, and to reported reserves, which refers to the highest level sum of
      individual entity estimates for which reserve estimates are
made.

	 	 	 
		
      Reported total reserves estimated by deterministic or
      probabilistic methods, whether comprised of a single reserves entity or an
      aggregate estimate for multiple entities, should target the following
      levels of certainty under a specific set of economic conditions:

	 	 	 
		a. 	
      There is a 90% probability that at least the estimated
      proved reserves will be recovered.

	 	 	 
		b. 	
      There is a 50% probability that at least the sum of the
      estimated proved reserves plus probable reserves will be
  recovered.

	 	 	 
		c. 	
      There is a 10% probability that at least the sum of the
      estimated proved reserves plus probable reserves plus possible reserves
      will be recovered.

	 	 	 
		
      A quantitative measure of the probability associated with
      a reserves estimate is generated only when a probabilistic estimate is
      conducted. The majority of reserves estimates will be performed using
      deterministic methods that do not provide a quantitative measure of
      probability. In principle, there should be no difference between estimates
      prepared using probabilistic or deterministic methods.

	 	 	 
		
      Additional clarification of certainty levels associated
      with reserves estimates and the effect of aggregation is provided in
      Section 5.5.3 of the COGE Handbook. Whether deterministic or probabilistic
      methods are used, evaluators are expressing their professional judgement
      as to what are reasonable estimates.

	 	 	 
	9. 	
      Pipeline Gas Reserves are gas reserves remaining
      after deducting surface losses due to process shrinkage and raw gas used
      as lease fuel.

	 	 	 
	10. 	
      Remaining Recoverable Reserves are the total
      remaining recoverable reserves associated with the acreage in which the
      Company has an interest.

	 	 	 
	11. 	
      Company Gross Reserves are the Company’s working
      interest share of the remaining reserves, before deduction of any
      royalties.




 





	Appendix A — Page
      4 



	12. 	
      Company Net Reserves are the gross remaining
      reserves of the properties in which the Company has an interest, less all
      Crown, freehold, and overriding royalties and interests owned by
      others.

	 	 
	13. 	
      Net Production Revenue is income derived from the
      sale of net reserves of oil, pipeline gas, and gas by-products, less all
      capital and operating costs.

	 	 
	14. 	
      Fair Market Value is defined as the price at which
      a purchaser seeking an economic and commercial return on investment would
      be willing to buy, and a vendor would be willing to sell, where neither is
      under compulsion to buy or sell and both are competent and have reasonable
      knowledge of the facts.

	 	 
	15. 	
      Barrels of Oil Equivalent (BOE) Reserves – BOE is
      the sum of the oil reserves, plus the gas reserves divided by a factor of
      6, plus the natural gas liquid reserves, all expressed in barrels or
      thousands of barrels.




 





	Appendix B — Page
      1 


Appendix B — Abbreviations, Units and Conversion Factors


This appendix contains a list of abbreviations found in Sproule
reports, a table comparing Imperial and Metric units, and conversion tables used
to prepare this report.

Abbreviations 

	AFE 	authority for expenditure 
	AOF 	absolute open flow 
	APO 	after pay out 
	BBg 	gas formation volume factor 
	BBo 	oil formation volume factor 
	bopd 	barrels of oil per day 
	bfpd 	barrels of fluid per day 
	BPO 	before pay out 
	BS&W 	basic sediment and water 
	BTU 	British thermal unit 
	bwpd 	barrels of water per day 
	CF 	casing flange 
	CGR 	condensate gas ratio 
	D&A 	dry and abandoned 
	DCQ 	daily contract quantity 
	DSU 	drilling spacing unit 
	DST 	drill stem test 
	EOR 	enhanced oil recovery 
	EPSA 	exploration and production sharing agreement
  
	FVF 	formation volume factor 
	GOR 	gas-oil ratio 
	GORR 	gross overriding royalty 
	GWC 	gas-water-contact 
	HCPV 	hydrocarbon pore volume 
	ID 	inside diameter 
	IOR 	improved oil recovery 
	IPR 	inflow performance relationship 
	IRR 	internal rate of return 
	k 	permeability 
	KB 	kelly bushing 
	LKH 	lowest known hydrocarbons 
	LNG 	liquefied natural gas 
	LPG 	liquefied petroleum gas 









	Appendix B — Page
      2 



	md 	millidarcies 
	MDT 	modular formation dynamics tester 
	MPR 	maximum permissive rate 
	MRL 	maximum rate limitation 
	NGL 	natural gas liquids 
	NORR 	net overriding royalty 
	NPI 	net profits interest 
	NPV 	net present value 
	OD 	outside diameter 
	OGIP 	original gas in place 
	OOIP 	original oil in place 
	ORRI 	overriding royalty interest 
	OWC 	oil-water-contact 
	P1 	proved 
	P2 	probable 
	P3 	possible 
	P&NG 	petroleum and natural gas 
	PI 	productivity index 
	ppm 	parts per million 
	PSU 	production spacing unit 
	PSA 	production sharing agreement 
	PSC 	production sharing contract 
	PVT 	pressure-volume-temperature 
	RFT 	repeat formation tester 
	RT 	rotary table 
	SCAL 	special core analysis 
	SS 	subsea 
	TVD 	true vertical depth 
	WGR 	water gas ratio 
	WI 	working interest 
	WOR 	water oil ratio 
	2D 	two-dimensional 
	3D 	three-dimensional 
	4D 	four-dimensional 
	1P 	proved 
	2P 	proved plus probable 
	3P 	proved plus probable plus possible 
	o API 	degrees API (American Petroleum Institute)
  



 





	Appendix B — Page
      3 


Imperial and Metric Units 

	Imperial Units 	  	Metric Units 
	M (103 )
    	one
      thousand 	Prefixes 	k (103 ) 	one
      thousand 
	MM (106 )
    	Million
    	 
    	M (106 ) 	million
    
	B (109 )
    	one
      billion 	 
    	T (1012 ) 	one
      billion 
	T (1012 )
    	one
      trillion 	 
    	E (1018 ) 	one
      trillion 
	  	  	  	G
      (109 ) 	one milliard 
	in. 	Inches
    	Length 	cm 	centimetres 
	ft 	Feet
	 
    	m 	metres
    
	mi 	Mile 	  	km 	kilometres 
	ft2 	square
      feet 	Area 	m2 	square
      metres 
	ac 	Acres 	  	ha 	hectares 
	cf or ft3
    	cubic
      feet 	Volume 	m3 	cubic
      metres 
	scf 	Standard cubic feet 	 
    	  	 
    
	gal 	Gallons
    	 
    	L 	litres
    
	Mcf 	Thousand cubic feet 	 
    	  	 
    
	Mcfpd 	Thousand cubic feet per day 	 
    	  	 
    
	MMcf 	million
      cubic feet 	 
    	  	 
    
	MMcfpd 	million
      cubic feet per day 	 
    	  	 
    
	Bcf 	billion
      cubic feet (109 ) 	 
    	  	 
    
	bbl 	Barrels
    	 
    	m3 	cubic
      metre 
	Mbbl 	Thousand barrels 	 
    	  	 
    
	stb 	stock
      tank barrel 	 
    	stm3 	stock
      tank cubic metres 
	bbl/d 	barrels
      per day 	 
    	m3 /d 	cubic
      metre per day 
	bbl/mo 	barrels per month 	  	 
    	  
	Btu 	British
      thermal units 	Energy 	J 	joules
    
	  	 
    	 
    	MJ/m3 	megajoules per cubic metre (106 ) 
	  	  	  	TJ/d
    	terajoule per day (1012 ) 
	oz 	ounce
    	Mass 	g 	gram
  
	lb 	pounds
    	 
    	kg 	kilograms 
	ton 	ton 	 
    	t 	tonne
    
	lt 	long
      tons 	 
    	  	 
    
	Mlt 	thousand long tons 	  	 
    	  
	psi 	pounds
      per square inch 	Pressure 	Pa 	pascals
    
	  	 
    	 
    	kPa 	kilopascals (103 ) 
	psia 	pounds
      per square inch absolute 	 
    	  	 
    
	psig 	pounds per square inch gauge 	  	 
    	  
	°F 	degrees
      Fahrenheit 	Temperature 	°C 	degrees
      Celsius 
	°R 	 
    	 
    	  	 
    
	  	degrees Rankine 	  	K 	Kelvin 
	M$ 	thousand dollars 	Dollars 	k$ 	thousand dollars 









	Appendix B — Page
      4 


Imperial and Metric Units (Cont’d) 

	Imperial Units 	  	Metric Units 
	sec 	second 	Time 	s 	second
    
	min 	minute 	  	min 	minute
    
	hr 	hour 	  	h 	hour
  
	day 	day 	  	d 	day
  
	wk 	week 	  	  	week
  
	mo 	month 	  	  	month
    
	yr 	year
    	  	a 	annum 


 







	Appendix B — Page
      5 


Conversion Tables 

	Conversion Factors — Metric to Imperial
  
	  	  	  
	cubic metres
      (m3 ) (@ 15°C) 	x 6.29010 	=
      barrels (bbl) (@ 60°F), water 
	m3 (@
      15°C) 	x 6.3300 	= bbl
      (@ 60°F), Ethane 
	m3 (@
      15°C) 	x 6.30001 	= bbl
      (@ 60°F), Propane 
	m3 (@
      15°C) 	x 6.29683 	= bbl
      (@ 60°F), Butanes 
	m3 (@ 15°C) 	x 6.29287 	= bbl (@ 60°F), oil, Pentanes Plus 
	m3 (@
      101.325 kPaa, 15°C) 	x 0.0354937 	=
      thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F) 
	1,000 cubic metres
      (103 m3 ) (@ 101.325 kPaa, 15°C) 	x 35.49373 	= Mcf
      (@ 14.65 psia, 60°F) 
	hectares (ha) 	x 2.4710541 	= acres
    
	1,000 square metres
      (103 m2 ) 	x 0.2471054 	= acres
    
	10,000 cubic metres (ha . m) 	x 8.107133 	= acre feet (ac-ft) 
	m3
      /103 m3 (@ 101.325 kPaa, 15° C) 	x 0.0437809 	=
      Mcf/Ac.ft. (@ 14.65 psia, 60°F) 
	joules (j) 	x 0.000948213 	= Btu
    
	megajoules per cubic
      metre (MJ/m3 ) (@ 101.325 kPaa, 	x 26.714952 	=
      British thermal units per standard cubic foot (Btu/scf) 
	15°C) 	  	(@
      14.65 psia, 60°F) 
	dollars per
      gigajoule ($/GJ) 	x 1.054615 	= $/Mcf
      (1,000 Btu gas) 
	metres (m) 	x 3.28084 	= feet (ft) 
	kilometres (km) 	x 0.6213712 	= miles
      (mi) 
	dollars per 1,000
      cubic metres ($/103 m3 ) 	x 0.0288951 	=
      dollars per thousand cubic feet ($/Mcf) (@ 15.025 psia) B.C. 
	($/103
      m3 ) 	x 0.02817399 	= $/Mcf
      (@ 14.65 psia) Alta. 
	dollars per cubic
      metre ($/m3 ) 	x 0.158910 	=
      dollars per barrel ($/bbl) 
	gas/oil ratio (GOR) (m3 /m3 ) 	x 5.640309 	= GOR (scf/bbl) 
	kilowatts (kW) 	x 1.341022 	=
      horsepower 
	kilopascals (kPa)
	x 0.145038 	= psi
    
	tonnes (t) 	x 0.9842064 	= long
      tons (LT) 
	kilograms (kg) 	x 2.204624 	=
      pounds (lb) 
	litres (L) 	x 0.2199692 	= gallons (Imperial) 
	litres (L) 	x 0.264172 	=
      gallons (U.S.) 
	cubic metres per
      million cubic metres (m3 /106 m3 ) (C )
    	x 0.177496 	=
      barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia) 
	     
                         
                         
                         
                         
         3 	  	 
    
	m3
      /106 m3 (C ) 	x 0.1774069 	=
      bbl/MMcf (@ 14.65 psia) 
	4 	  	 
    
	m3
      /106 m3 (C ) 	x 0.1772953 	=
      bbl/MMcf (@ 14.65 psia) 
	5+ 	  	 
    
	tonnes per million cubic metres (t/106 m3
      ) (sulphur) 	x 0.0277290 	= LT/MMcf (@ 14.65 psia) 
	millilitres per
      cubic meter (mL/m3 ) (C ) 	x 0.0061974 	=
      gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf) 
	     
                         
                         
                       5+ 	  	 
    
	(mL/m3 )
      (C ) 	x 0.0074428 	=
      gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf) 
	     
                 5+ 	  	 
    
	Kelvin (K) 	x 1.8 	=
      degrees Rankine (°R) 
	millipascal seconds (mPa . s) 	x 1.0 	= centipoise 


 







	Appendix B — Page
      6 


Conversion Tables (Cont’d) 

	Conversion Factors — Imperial to Metric
  
	  	  	  
	barrels (bbl) (@
      60°F) 	x 0.15898 	= cubic
      metres (m3 ) (@ 15°C), water 
	bbl (@ 60°F) 	x 0.15798 	=
      m3 (@ 15°C), Ethane 
	bbl (@ 60°F) 	x 0.15873 	=
      m3 (@ 15°C), Propane 
	bbl (@ 60°F) 	x 0.15881 	=
      m3 (@ 15°C), Butanes 
	bbl (@ 60°F) 	x 0.15891 	= m3 (@ 15°C), oil, Pentanes Plus 
	thousands of cubic
      feet (Mcf) (@ 14.65 psia, 60°F) 	x 28.17399 	=
      m3 (@ 101.325 kPaa, 15°C) 
	Mcf (@ 14.65 psia,
      60°F) 	x 0.02817399 	= 1,000
      cubic metres (103 m3 ) (@ 101.325 kPaa, 15°C) 
	acres 	x 0.4046856 	=
      hectares (ha) 
	acres 	x 4.046856 	= 1,000
      square metres (103 m2 ) 
	acre feet (ac-ft) 	x 0.123348 	= 10,000 cubic metres (104 m3
      ) (ha . m) 
	Mcf/ac-ft (@ 14.65
      psia, 60°F) 	x 22.841028 	=
      103 m3 /m3 (@ 101.325 kPaa, 15°C) 
	Btu 	x 1054.615 	=
      joules (J) 
	British thermal
      units per standard cubic foot (Btu/Scf) (@ 14.65 psia, 	x 0.03743222 	=
      megajoules per cubic metre (MJ/m3 ) (@ 101.325 kPaa, 
	60°F) 	  	15°C)
    
	$/Mcf (1,000 Btu
      gas) 	x 0.9482133 	=
      dollars per gigajoule ($/GJ) 
	$/Mcf (@ 14.65 psia, 60°F) Alta. 	x 35.49373 	= $/103 m3 (@ 101.325 kPaa,
      15°C) 
	$/Mcf (@ 15.025
      psia, 60°F), B.C. 	x 34.607860 	=
      $/103 m3 (@ 101.325 kPaa, 15°C) 
	feet (ft) 	x 0.3048 	=
      metres (m) 
	miles (mi) 	x 1.609344 	=
      kilometres (km) 
	$/bbl 	x 6.29287 	=
      $/m3 (average for 30°-50° API) 
	GOR (scf/bbl) 	x 0.177295 	= gas/oil ratio (GOR) (m3 /m3
      ) 
	horsepower 	x 0.7456999 	=
      kilowatts (kW) 
	psi 	x 6.894757 	=
      kilopascals (kPa) 
	long tons (LT) 	x 1.016047 	=
      tonnes (t) 
	pounds (lb) 	x 0.453592 	=
      kilograms (kg) 
	gallons (Imperial) 	x 4.54609 	= litres (L) (.001 m3 ) 
	gallons (U.S.) 	x 3.785412 	=
      litres (L) (.001 m3 ) 
	barrels per million
      cubic feet (bbl/MMcf) (@ 14.65 psia) (C ) 	x 5.6339198 	= cubic
      metres per million cubic metres (m3 /106 m3
      ) 
	     
                         
                         
                         
                         
                     3 	  	 
    
	bbl/MMcf (C ) 	x 5.6367593 	=
      (m3 /106 m3 ) 
	     
                   4 	  	 
    
	bbl/MMcf (C ) 	x 5.6403087 	=
      (m3 /106 m3 ) 
	     
                   5+ 	  	 
    
	LT/MMcf (sulphur) 	x 36.063298 	= tonnes per million cubic metres (t/106
      m3 ) 
	gallons (Imperial)
      per thousand cubic feet (gal (Imp)/Mcf) (C ) 	x 161.3577 	=
      millilitres per cubic meter (mL/m3 ) 
	     
                         
                         
                         
                         
                         5+
	  	 
    
	gallons (U.S.) per
      thousand cubic feet (gal (U.S.)/Mcf) (C ) 	x 134.3584 	=
      (mL/m3 ) 
	     
                         
                         
                         
                         
                   5+ 	  	 
    
	degrees Rankine (°R)
    	x 0.555556 	=
      Kelvin (K) 
	centipoises 	x 1.0 	= millipascal seconds (mPa . s)