technical assessment of the undiscovered ...a summary of the lands held by the company in the nogal...

TECHNICAL ASSESSMENT

OF

THE UNDISCOVERED RESOURCES ASSOCIATED WITH

THE NOGAL VALLEY AND DHAROOR VALLEY BLOCKS

PUNTLAND, SOMALIA

(As of January 31, 2007)

Geological and Petroleum Engineering Consultants

Suite 900, North Tower, Sun Life Plaza, 140 – 4th Avenue S.W.

Calgary, Alberta, Canada T2P 3N3 Tel: (403) 294-5500 Fax: (403) 294-5590 Fax: (403) 294-5580

Copies: Canmex Minerals Corporation (5 copies) Sproule International Limited (1 copy) Electronic (2 copies) Project No.: 3712.70399 Prepared For: Canmex Minerals Corporation Author: Douglas J. Carsted, P.Geol. Exclusivity: This report has been prepared for the exclusive use of Canmex Minerals

Corporation, 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.

Table of Contents — Page 1

Table of Contents Introduction Disclaimer Assessment Procedures Exclusivity Certification Summary Table S-1 Summary of the Unproved Properties Table S-2a Summary of the Gross Undiscovered In-Place Oil Resources Table S-2b Summary of the Net Undiscovered In-Place Oil Resources Discussion General Overview Geological Review Conclusions Tables Table 1a Nogal Valley Block, Puntland, Somalia, Probabilistic Estimate of

Gross Undiscovered In-Place Oil Resources Table 1b Nogal Valley Block, Puntland, Somalia, Probabilistic Estimate of Net

Undiscovered In-Place Oil Resources

3712.70399.DJC.ml Sproule

J:\Canmex Minerals Corp Somalia 70399\Report\Summary.doc

Table of Contents — Page 2

Figures Figure 1 Location Map Figure 2 Satellite Image of Puntland Showing Nogal and Darin Basins Figure 3 Generalized Stratigraphy of Puntland with potential reservoirs, source rocks and seals Appendices Appendix A Definitions Appendix B Abbreviations Appendix C Unproved Properties



Introduction — Page 1

Introduction This report was prepared during January and February 2007, by qualified evaluators and auditors of Sproule International Limited (“Sproule”) at the request of Mr. Richard H. Schmitt, President & CEO, Canmex Minerals Corporation, of Calgary, Alberta, Canada. Canmex Minerals Corporation is hereinafter referred to as “the Company”. The report consists of a technical assessment of the undiscovered in-place oil resources associated with the Nogal Valley Block (Nogal Basin) and the Dharoor Valley Block (Darin Basin), both located in the semi-autonomous state of Puntland, Somalia. The Company has advised that the blocks are held 20 percent by Range Resources Ltd. and 80 percent by Canmex Minerals Corporation. Figure 1 shows the outline of the Nogal Valley and Dharoor Valley blocks, which have been configured to encompass the Nogal and Darin sedimentary basins respectively. Using data provided by the Company, data available in the public domain and from the non-confidential files of Sproule, an assessment was made of the undiscovered oil resources of the Nogal Valley Block. At the time this report was prepared, Sproule was unable to make an assessment of the undiscovered resources associated with the Dharoor Valley Block (Darin Basin) due to a lack of data. The Darin and Nogal sedimentary basins are thought to have very similar geological histories and, as such, it is surmised that the undiscovered resources associated with the Dharoor Valley Block might be similar to that of the Nogal Valley Block. The estimates for the Nogal Valley Block are based on a probabilistic model of the expected reservoir parameters of prospective reservoirs and traps that may be encountered within the block. The reservoir parameters of porosity, water saturation, pay thickness, area and formation volume factors were selected based on the available data and are considered to represent the range of possible values that may be encountered by future exploration wells. As no commercial discoveries have been made on either of the blocks as of the effective date of this report, no proved, probable or possible reserves have been assigned to the blocks at this time and the lands have been assessed as unproved properties. As of the effective date of this report, the Company owns an 80 percent working interest in the blocks addressed in this report. The undiscovered resources referred to in this report are reported herein as the total 100 percent in place volumes and as the Company’s 80 percent working interest.




This one volume report contains an Introduction, Summary and Discussion accompanied by pertinent Tables, Figures, and Appendices. The Introduction includes Sproule’s disclaimer and pertinent author certificates, the Summary presents a high-level summary of the review, and the Discussion includes our commentary pertaining to the assessment of the blocks. The definitions used in this report are in accordance with those presented in the Canadian Oil and Gas Evaluators Handbook (COGEH). Disclaimer This report has been prepared by qualified evaluators and auditors of Sproule International Limited using current geological and engineering knowledge and techniques. It has been prepared within the Code of Ethics of the Association of Professional Engineers, Geologists and Geophysicists of Alberta. Nevertheless, the assessment presented in this report could be affected by the data received, and the procedures used by Sproule International Limited, as qualified below. 1. Property descriptions, details of interests held, and well data, as obtained from the

Company, or public sources, were accepted as represented. No further investigation was made into either the legal titles held or any operating agreements in place relating to the subject properties.

2. In the preparation of this review, a field inspection of the holdings was not undertaken.

Certain relevant geological data were made available by the Company, or were obtained from public sources or from the non-confidential files of Sproule.

The certificates of those evaluators involved in the preparation of this report have been included. Assessment Procedures In the technical review of the unproved properties, all known pertinent factors including geologic structures, prospective producing zones, terrain and accessibility, access to markets, priced paid by other operators for lands with similar geological prospects, risk and the economics of exploration, development and production have been considered. No estimate of fair market value for these lands has been included, but estimates of resource potential have been made.




Exclusivity This report has been prepared for the exclusive use of Canmex Minerals Corporation. It may 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 Associates Limited, and without the complete contents of the report being made available to that party.




Certification Report Preparation The report entitled “Technical Assessment of the Undiscovered Resources Associated with the Nogal Valley and Dharoor Valley Blocks, Puntland, Somalia (As of January 31, 2007),” was prepared by the following Sproule personnel:

_______________________________________

Douglas J. Carsted, P.Geol. Project Leader; Vice-President, Geoscience / /2007 dd/mm/yr

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

________________________________________

John L. Chipperfield, P.Geol. Vice-President, Geoscience / /2007 dd/mm/yr

Permit to Practice Sproule Associates Limited is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and our permit number is P417.



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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 “Technical Assessment of the Undiscovered Resources

Associated with the Nogal Valley and Dharoor Valley Blocks, Puntland, Somalia (As of January 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 Canmex Minerals Corporation.

Douglas J. Carsted, P.Geol.



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Original signed by Douglas J. Carsted


Certificate

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

I, John L. Chipperfield, Senior Vice-President (Geoscience) 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 “Technical Assessment of the Undiscovered Resources

Associated with the Nogal Valley and Dharoor Valley Blocks, Puntland, Somalia (As of January 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 Associates 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 Canmex Minerals Corporation.

John L. Chipperfield, P.Geol.



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Original signed by John L. Chipperfield

Summary — Page 1

Summary This report is based on interpreted technical data including seismic structure maps, well logs, seismic cross-sections, and other information supplied by the Company, published information and our personal knowledge of the geology and economics of oil and gas exploration, development and production in these areas of North Africa. A summary of the lands held by the Company in the Nogal Valley Block (Nogal Basin) and the Dharoor Valley Block (Darin Basin), both located in the semi-autonomous state of Puntland, Somalia, as of January 31, 2007, is presented in Table S-1. No proved or probable reserves have been assigned to these holdings at this time and they have been assessed as unproved properties. The Company and their partner Range Resources Limited have signed two Production Sharing Agreements (PSA) with the Government of Puntland. One covering the Nogal Basin referred to as the Nogal Valley Block and the second covering the Darin Basin referred to as the Dharoor Valley Block. The terms of both agreements are identical.

Table S-1 Summary of Unproved Properties

Puntland, Somalia

Area Working Interest Gross Acres Net Acres

Nogal Valley Block (Nogal Basin) 80% 12,849,479 10,279,583

Dharoor Valley Block (Darin Basin) 80% 7,166,056 5,732,845

Total Unproved Properties 20,015,535 16,012,428 Under National Instrument (NI) 51-101, companies are permitted to disclose resources, in addition to reserves, based on the classification criteria defined in the Canadian Oil and Gas Evaluation Handbook (COGEH). Additional guidance concerning disclosure of resources is provided in the Canadian Securities Administrators (CSA) Staff Notice 51-321, issued in November 2006; in particular, this notice provides guidance concerning disclosure of undiscovered resources and permits the disclosure of such resources as in-place volumes, rather than recoverable volumes.



Summary — Page 2

The COGEH definitions permit the subdivision of undiscovered resources into recoverable and unrecoverable categories. The recoverable category consists of prospective resources, (which are technically recoverable and economic) and unrecoverable resources (which are neither technically recoverable nor economic), neither of which are applicable to the undiscovered resources estimated to exist on the land holdings at this time. Thus, the oil resources estimated to exist on the Nogal Valley Block are reported as undiscovered in-place volumes. A summary of the gross undiscovered in-place oil resources estimated to exist within the Nogal Valley Block, as of January 31, 2007, is presented in Table S-2a, as follows:

Table S-2a Summary of Undiscovered In-Place Oil Resources

Puntland, Somalia

Gross Oil-in-Place (MMbbls)1

Area Low Estimate Best Estimate High Estimate

Nogal Valley Block (Nogal Basin) 2,213 4,301 10,397

Total Unproved Properties 2,213 4,301 10,397 1 Unrisked

A summary of the net undiscovered oil resources estimated to exist within the Nogal Valley and, as of January 31, 2007, is presented in Table S-2b, as follows:

Table S-2b Summary of Undiscovered In-Place Oil Resources

Puntland, Somalia

Net1 Oil-in-Place (MMbbls)2

Area Low Estimate Best Estimate High Estimate

Nogal Valley Block (Nogal Basin) 1,770 3,441 8,318

Total Unproved Properties 1,770 3,441 8,318 1 Company Net Interest 80 Percent 2 Unrisked



Summary — Page 3

There is no certainty that any portion of the undiscovered resources will be discovered and that, if discovered, it may not be economically viable or technically feasible to produce. In reviewing the lands, we have taken into account all known available pertinent factors, such as lands having similar geological prospects, geological structures, prospective producing zones, level of exploration and development activity, terrain, accessibility, access to markets, operating status of the lands, and acquisition costs. Estimates of resource potential have been made. No fair market value has been assigned to these lands at this time.



Discussion — Page 1

Discussion General Overview The location of the Nogal Valley and Dharoor Valley Blocks situated in northern Somalia is shown in Figure 1. The two blocks cover the Nogal Basin and the Darin Basin, respectively. Combined, the two blocks cover a very large area, with the Nogal Valley Block extending over approximately 12,849,479 acres, which encompasses the Nogal Basin. The Dharoor Valley Block extends over an area of 7,166,056 acres, encompassing the entire Darin Basin. These areas are very large and, with only 5 wells drilled, the area remains one of the least explored areas in North Africa. In the early 1990’s civil unrest in the country precipitated the pullout of the oil companies operating in the country at the time including Amoco, Chevron, Agip and Conoco. The Company with their partners Range Resources Limited signed two Production Sharing Agreements (PSA) with the Government of Puntland on January 17th 2007. One covering the Nogal Basin referred to as the Nogal Valley Block and the second covering the Darin Basin referred to as the Dharoor Valley Block. The terms and articles of both agreements are identical as are the value of the work commitments for the exploration phase. The Nogal Basin covered by the Nogal Valley Block has been identified as having reservoir, source rock and trap potential. International oil and gas companies conducted exploration in the late 1980’s in the region. During this exploration phase, a grid of 2D seismic was shot perpendicular to the axis of the rift system in the Nogal Basin. Based on interpreted maps provided by the Company, this data shows a number of large, closed, fault-controlled structures. In addition, surface geology identified a number of oil seeps along the main basin-bounding faults. Several wells drilled on the identified structures encountered numerous oil shows, however, the wells Nogal-1 and Kalis-1 did not reach the main exploration target, for reasons unknown. No data was available for the Dharoor Valley Block and, as a result, it has not been assessed in this report. Geological Review The most clearly defined basins in Puntland are the Nogal and Darin basins. These large depressions are visible on satellite imagery (Figure 2). The two basins are believed to be part of a failed rift system and are analogous to the prolific Yemen rift system found across the Gulf of Aden. It is thought that the oil reserves found in the Cretaceous and Jurassic sedimentary




sequence in Yemen could also be present in similar formations in the northern portion of Somalia, since these two areas were joined approximately 18 million years ago, before the movement of the Indian plate away from the African plate. A generalized stratigraphic column showing the ages of the sediments is shown as Figure 3. The basin fill is extremely thick, with more than 10,000 feet of sediments in some areas. In this analysis, three reservoirs were considered, with the main target reservoir being the Jurassic-aged sandstones belonging to the Gabredarre Formation. These reservoir sandstones overlie the organic rich shales and marls of the Uarandab Formation, which is thought to be the source rock for the oil seeps observed along the boundary faults. The secondary reservoirs include the deep marine sandstones and shallow marine carbonates belonging to the Upper Cretaceous Gumburo Formation. The marine sandstones of the Jesomma Formation, also Upper Cretaceous in age, are also potential secondary targets. The Jesomma and Gumburo have isopach thicknesses of approximately 1,350 and 2,450 feet, respectively. Petrophysical log data for the exploration wells was not available at the time of this assessment so reports prepared by previous major oil company operators were used to develop ranges of porosity, water saturation, net reservoir thickness area, oil shrinkage and recovery factors used in the probabilistic analysis. The following table lists the range of the various reservoir parameters used in the analysis.

Nogal Valley Block Range of Reservoir Parameters

Zone Jesomma (Cretaceous) Gumburo (Cretaceous) Gabredarre (Jurassic)

Reservoir Type

Sandstone Sandstone /Carbonate Sandstone

Hydrocarbon Type

Oil Oil Oil

Range Minimum Maximum Minimum Maximum Minimum Maximum

Porosity (%) 13 21 8 13 15 25

Water Saturation (%)

31 49 36 58 23 37

Net Reservoir Thickness (ft)

20 100 20 200 20 200

Area (acres) The areas where taken as a log normal distribution with a minimum (P90) of 160 acres and

the maximum (P10) was varied from 1200 to 14200 acres within the 7 potential structures.

1/Bo (stb/rbbl) 0.77 0.91 0.77 0.91 0.77 0.91

Recovery Factor (%)

12.5 30 1.25 30 12.5 30




The ranges of values use are thought to be geologically reasonable. For the Nogal Valley Block, a total of seven structures, each with three prospective zones or play types, were considered. These were not specific prospects but generic structures with the range of sizes estimated from the two seismic time structure maps reviewed. The seismic maps reviewed showed additional leads that have not been incorporated into this analysis due to the limited data available at the time this report was prepared. The limited information available for review by Sproule indicates that reservoir quality rocks are present within the Nogal Basin. Of the five wells drilled in the Nogal Basin, images of partial well logs were provided for two wells (Nogal 1 and Kalis-1). The drilling reports for these two wells indicated that the Jurassic sandstone targets were not reached but that oil shows were found in some of the shallower sandstones. Nogal –1 was drilled to a depth of 10,736 feet in 1990. Kalis-1 was drilled to at least a depth of 5100 feet in 1990 according to log images reviewed. The original plan for Kalis-1 was to drill it to a depth of 14,850 feet. Surface seeps of oil, as well as oil shows reported in several exploration wells drilled by previous operators in the area, indicate that the source rocks have generated hydrocarbons and that they have migrated through the system. There is not enough data to determine if trap formation predates hydrocarbon migration, however, we have made that assumption in our assessment. The indications from the limited number of wells drilled in the basin are that the basin appears to be oil-prone and as such, only oil accumulations were considered in the model. Gas in small quantities would not be economic to produce and it would have to be determined if even large volumes of gas if discovered would be economic. Seismic structure maps prepared in the late 1980’s by a major oil company and obtained from the Somali Government by the Company show that a number of fault-bounded structures with three way dip closures do exist within the basin. A seismic base map for the basin indicates that approximately 2500 line miles of 2D seismic has been shot representing some 76 seismic lines. Three seismic lines were available for review and showed good structuring in the subsurface with evidence of tilted fault blocks and rollover closure. The vintage of the seismic data is unknown but the quality appears to be good for those lines examined. The structures identified by the major oil company using the seismic data, appear to be quite large with some in excess of 4,000 acres and as large as 14,000 acres. These, combined with the extremely thick section of basin fill, provide multiple horizons in which hydrocarbons can be trapped. Only structural traps have been considered in this analysis. There is potential for stratigraphic trapping of hydrocarbons within the basin, however, these types of traps are difficult to explore for without good well control. Stratigraphic traps may be discovered in the future as new wells are drilled in the basin.




For each play / reservoir, a range of reservoir parameter values for porosity, water saturation, area, net pay, shrinkage factors were modeled within a probabilistic software package, using either triangular or log-normal distributions. The lognormal distributions were modeled using assumed P10 and P90 end points. The model was run using 10,000 samples, from which a distribution of possible outcomes was created. The totals for each zone were summed statistically in order to estimate an aggregated expected outcome. Note that the sum of individual volumes for each play type will not equal the volume estimated for the aggregated expected outcome. The following table indicates the zone / play types considered for the Nogal Valley Block.

Nogal Valley Block Play and Hydrocarbon Types

Zone/Play Type Reservoir Type Hydrocarbon Type

Jesomma (Cretaceous) Sandstone Oil

Gumburo (Cretaceous) Sandstone /Carbonate Oil

Gabredarre (Jurassic) Sandstone Oil

As previously noted, there was insufficient data available for the Dharoor Valley Block to assess the potential within the Darin Basin. The size and proximity to the Nogal Basin suggest that it has had a similar geologic history and, as such, should have similar prospectivity to the Nogal Basin. Future exploration will be needed in order to assess this large area to determine its potential.




Minimum Work Obligations Both PSA’s signed by the Company with their partners Range Resources Limited stipulate the length of time for each of the Exploration and Production Periods. As both agreements are the same, the information set out below applies to both the Nogal Valley Exploration Area and the Dharoor Valley Exploration Area. In the agreements that were reviewed by Sproule, the Minimum Work Obligations are set out as follows:

• First Exploration Period: Duration period 36 months Minimum expenditure US$ 5,000,000

• Second Exploration Period: Duration 36 months with a 6 month extension if requested prior to 30 days from the expiry of the Exploration Period.

Minimum expenditure US$ 5,000,000 The work program for the Nogal Valley Exploration Area is listed as;

i. Geological fieldwork; ii. Acquisition of surface high resolution geochemical surveys; iii. Reprocessing of prior 2D seismic (up to an aggregate of 1,000 line km); iv. Review and integration of all geophysical and geological data; and v. Drilling of two exploratory wells (over First (minimum one well) and Second

Exploration Periods). Should the Company make a Commercial Discovery a 20-year Development Period is put in place with the option of extending this period by up to 5 years upon written notice 6 months prior to the expiry of the Development Period. The royalty rate for the produced crude oil is set as a sliding scale with reasonable rates. The work obligation set out in both agreements is considered to be reasonable and achievable by the Company, given the potential 6.5 year exploration period. The minimum expenditure of US$ 10,000,000 for each PSA for the work commitments is also considered to be reasonable for an international project of this nature. The royalty rates prescribe in the event of a commercial discovery and production are also considered to be reasonable.




Conclusions Based on the Monte Carlo probabilistic model built for the Nogal Valley Block, low, best and high estimates for the undiscovered in-place oil resources were made and the results are presented in Table 1a for the gross volumes and Table 1b for the net volumes. These volumes are reported as unrisked volumes and Sproule has not applied any economic criteria in the estimation of these resources. The exploration periods and the development periods set forth in the Production Sharing Agreement are reasonable, as are the royalty rates for oil production from both the Nogal Valley Exploration Area and the Dharoor Valley Exploration Area. The minimum work program expenditure of US$ 10,000,000 over the six years of exploration (US$ 5,000,000 in the first 3 years and US$ 5,000,000 in the last 3 years) for each PSA is reasonable given the potential of the exploration acreage. There is no certainty that any portion of the undiscovered resources will be discovered and that, if discovered, it may not be economically viable or technically feasible to produce.

Table 1a Nogal Valley Block, Puntland, Somalia

Probabilistic Estimate of Gross Undiscovered In-Place Oil Resources1

Low Estimate Best Estimate High Estimate Zone/Play Type OOIP MMbbls OOIP MMbbls OOIP MMbbls

Oil Jesomma (Sandstone) 192 449 1,316 Gumburo (Carbonate) 350 916 3,436 Gabrodarre (Sandstone) 929 2,225 6,465

Total* 2,213 4,301 10,397 1 Unrisked * Note: The total reported is the sum of all the Probabilistic cases and will not equal the arithmetic sum of the individual zone or play type due to statistics.




Table 1b Nogal Valley Block, Puntland, Somalia

Probabilistic Estimate of Net1 Undiscovered In-Place Oil Resources2

Low Estimate Best Estimate High Estimate Zone/Play Type OOIP MMbbls OOIP MMbbls OOIP MMbbls

Oil Jesomma (Sandstone) 154 359 1,053 Gumburo (Carbonate) 280 733 2,749 Gabrodarre (Sandstone) 743 1,780 5,172

Total* 1,770 3,441 8,318 1 Company Net WI 80 percent 2 Unrisked * Note: The total reported is the sum of all the Probabilistic cases and will not equal the arithmetic sum of the individual zone or play type due to statistics.



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. Possible reserves have not been considered in this report.




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.




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 judgment 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.




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. Equivalent reserves can also be expressed in thousands of cubic feet of gas equivalent (McfGE) using a conversion ratio of 1 bbl:6 Mcf.



Appendix B — Page 1

Appendix B — Abbreviations This appendix contains a list of abbreviations that may be found in Sproule reports, as well as a table comparing Imperial and Metric units. Two conversion tables, used to prepare this report, are also provided. AOF absolute open flow BOE barrels of oil equivalent bopd barrels of oil per day bwpd barrels of water per day DCQ daily contract quantity DSU drilling spacing unit GCA gas cost allowance GOR gas-oil ratio GORR gross overriding royalty LPG liquid petroleum gas McfGE thousands of cubic feet of gas equivalent Mcfpd thousands of cubic feet per day MPR maximum permissive rate MRL maximum rate limitation NCI net carried interest NGL natural gas liquids NORR net overriding royalty NPI net profits interest ORRI overriding royalty interest P&NG petroleum and natural gas PSA Production Sharing Agreement PSU production spacing unit PVT pressure-volume-temperature WI working interest




Imperial Units Metric Units M (103) one thousand Prefixes k (103) one thousand

MM (106) million M (106) million

B (109) one billion G (109) one billion

T (1012) one trillion T (1012) one trillion

E (1018) 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




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




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 (103m3) (@ 101.325 kPaa, 15°C) x 35.49373 = Mcf (@ 14.65 psia, 60°F)

hectares (ha) x 2.4710541 = acres

1,000 square metres (103m2) x 0.2471054 = acres

10,000 cubic metres (ha.m) x 8.107133 = acre feet (ac-ft)

m3/103m3 (@ 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,

15°C)

x 26.714952 = British thermal units per standard cubic foot (Btu/scf)

(@ 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 ($/103m3) x 0.0288951 = dollars per thousand cubic feet ($/Mcf) (@ 15.025 psia) B.C.

($/103m3) 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 (m3/106m3) (C3) x 0.177496 = barrels per million cubic feet (bbl/MMcf) (@ 14.65 psia)

m3/106m3) (C4) x 0.1774069 = bbl/MMcf (@ 14.65 psia)

m3/106m3) (C5+) x 0.1772953 = bbl/MMcf (@ 14.65 psia)

tonnes per million cubic metres (t/106m3) (sulphur) x 0.0277290 = LT/MMcf (@ 14.65 psia)

millilitres per cubic meter (mL/m3) (C5+) x 0.0061974 = gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf)

(mL/m3) (C5+) x 0.0074428 = gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf)

Kelvin (K) x 1.8 = degrees Rankine (°R)

millipascal seconds (mPa.s) x 1.0 = centipoise




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 (103m3) (@ 101.325 kPaa, 15°C)

acres x 0.4046856 = hectares (ha)

acres x 4.046856 = 1,000 square metres (103m2)

acre feet (ac-ft) x 0.123348 = 10,000 cubic metres (104m3) (ha.m)

Mcf/ac-ft (@ 14.65 psia, 60°F) x 22.841028 = 103m3/m3 (@ 101.325 kPaa, 15°C)

Btu x 1054.615 = joules (J)

British thermal units per standard cubic foot (Btu/Scf) (@ 14.65 psia,

60°F)

x 0.03743222 = megajoules per cubic metre (MJ/m3) (@ 101.325 kPaa,

15°C)

$/Mcf (1,000 Btu gas) x 0.9482133 = dollars per gigajoule ($/GJ)

$/Mcf (@ 14.65 psia, 60°F) Alta. x 35.49373 = $/103m3 (@ 101.325 kPaa, 15°C)

$/Mcf (@ 15.025 psia, 60°F), B.C. x 34.607860 = $/103m3 (@ 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) (C3) x 5.6339198 = cubic metres per million cubic metres (m3/106m3)

bbl/MMcf (C4) x 5.6367593 = (m3/106m3)

bbl/MMcf (C5+) x 5.6403087 = (m3/106m3)

LT/MMcf (sulphur) x 36.063298 = tonnes per million cubic metres (t/106m3)

gallons (Imperial) per thousand cubic feet (gal (Imp)/Mcf) (C5+) x 161.3577 = millilitres per cubic meter (mL/m3)

gallons (U.S.) per thousand cubic feet (gal (U.S.)/Mcf) (C5+) x 134.3584 = (mL/m3)

degrees Rankine (°R) x 0.555556 = Kelvin (K)

centipoises x 1.0 = millipascal seconds (mPa.s)



Appendix C — Page 1

Appendix C — Unproved Properties

Definitions Unproved properties are defined as those holdings or zones to which proved or probable or possible reserves have not been assigned. In holdings where proved, probable or possible reserves values have been included for one or more zones, an additional value would be assigned for unproved prospects in the remaining potential zones. Assessment Procedure Regional and local structural and stratigraphic features and trends provided the principal criteria for the technical review of the unproved properties, but other factors were also considered, where pertinent. A summary of the main criteria considered is given below where data was available or deemed necessary. 1. Prices paid. 2. Local and regional geological, geochemical and geophysical features. 3. Other regional and local subsurface information from deep test holes and other subsurface

geophysical data. 4. Terrain and accessibility. 5. Proximity to main pipeline outlets. 6. Proximity to transportation. 7. Company concerned in the case of farmouts. 8. Farmout deal involved. 9. Overrides and other continent interests involved. 10. Proximity to known discoveries that are likely to affect market outlets. 11. Economics of exploration, development and production. 12. Market situation. 13. Work commitments and minimum required expenditures. In accordance with National Instrument 51-101, a series of review procedures is to be followed during the assessment of unproved lands. For the sake of clarity, these methods are herein presented and form the basis for the current assessment. During the course of the review, and in the text of this report, the points within Items 6.2 have been addressed. The fair market value of these lands has not been presented in this report.




National Instrument 51-101 Requirements Other Oil and Gas Information Item 5.9 – Disclosure Concerning Prospects If a reporting issuer discloses anticipated results from a prospect, the reporting issuer shall also disclose in writing, in the same document or in a supporting filing, in respect of the prospect: (a) the location and basin name; (b) the reporting issuer’s gross and net interest in the property, expressed in units of area

(acres or hectares); (c) in the case of undeveloped property in which the reporting issuer holds a leasehold

interest, the expiry date of that interest; (d) the name, geologic age, and lithology of the target zone; (e) the distance to the nearest analogous commercial production; (f) the product types reasonably expected; (g) the range of pool or field sizes; (h) the depth of the target zone; (i) the estimated cost to drill and test a well to the target depth; (j) reasonably expected drilling commencement and completion dates; (k) the anticipated prices to be received for each product type reasonably expected; (l) reasonably expected marketing and transportation arrangements; (m) the identity and relevant experience of the operator; (n) risks and probability of success; and (o) the application information specified in Section 5.10. Item 5.10 – Estimates of Fair Value of an Unproved Property, Prospect or Resource 1. If a reporting issuer discloses in writing an estimate of the fair value of an unproved

property, prospect or resource, or discloses expected results from a prospect, the disclosure shall include all positive and negative factors relevant to the estimate or expectation.

2. If a reporting issuer discloses in writing an estimate of the fair value of an unproved property, prospect or resource: (a) in the case of an estimate of the fair value of an unproved property, except as

provided in paragraph (b), the estimate shall be based on the first applicable item




listed below, and that item shall be described as the basis of the estimate in the document containing the disclosure or in a supporting filing;

i. the acquisition cost to the reporting issuer, provided that there have been no

material changes in the unproved property, the surrounding properties, or the general oil and gas economic climate since acquisition;

ii. recent sales by others of interest in the same unproved property; iii. terms and conditions, expressed in monetary terms, of recent farmin agreements

related to the unproved property; iv. terms and conditions, expressed in monetary terms, of recent work commitments

related to the unproved property; v. recent sales of similar properties in the same general area; (b) in the case of an estimate of fair market value to which none of the items listed in

paragraph (a) applies: i. the estimate shall be prepared or accepted by a professional valuator (who is not

a “related party” of the reporting issuer within the meaning of the term as used in the CICA Handbook) applying valuation standards established by the professional body of which the valuator is a member and from which the valuator derives professional standing;

ii. the estimate shall consist of at least three values that reflect a range of reasonable likelihoods (the low value being conservative, the middle value being the median, and the high value being optimistic) reflecting courses of action expected to be followed by the reporting issuer;

iii. the estimate, and the identities of the professional valuator and of the professional body referred to in subparagraph (i) shall be set out in the document containing the disclosure or in a supporting filing; and

iv. the reporting issuer shall obtain from the professional valuator referred to in subparagraph (i):

(A) a report of the estimate that does not contain (i) a disclaimer that materially detracts from the usefulness of the estimate;

or (ii) a statement that the report may not be relied on; and (B) the professional valuator’s written consent to the disclosure of the report by

the reporting issuer to the public.




Item 6.2 – Properties With No Attributed Reserves 1. For unproved properties, disclosure: (a) the gross area (acres or hectares) in which the reporting issuer has an interest; (b) the interest of the reporting issuer therein expressed in terms of net area (acres or

hectares); (c) the location, by country; and (d) the existence, nature (including any bonding requirements), timing and cost

(specified or estimated) of any work commitments. 2. Disclose, by country, the net area (acres or hectares) of unproved property for which the

reporting issuer expects its rights to explore, develop and exploit to expire within one year.



technical assessment of the undiscovered ...a summary of the lands held by the company in the nogal...

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