resource assessment of the kaheru …...2011/08/09 · certificates summary table s-1 gross...

RESOURCE ASSESSMENT OF THE KAHERU PROSPECT

IN THE PERMIT PEP 52181, TARANAKI BASIN, NEW ZEALAND

(As of May 31, 2011)

FOR TAG OIL LIMITED

Copies: TAG OIL Limited (4 copies) Sproule International Limited (1 copy) Electronic (1 copy) Project No.: 3219.70639 Prepared For: TAG OIL Limited Authors: Barrie F. Jose, P.Geoph., Project Leader Alexey Romanov, Ph.D., M.Sc. Suryanarayana Karri, P.Geoph. Douglas J. Carsted, P.Geol. Exclusivity: This report has been prepared for the exclusive use of TAG OIL

Limited. 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 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 Gross Undiscovered In-Place and Prospective Resources

(Unrisked) Kaheru Area, Taranaki Basin, New Zealand (As of May 31, 2011) Discussion 1.0 General 2.0 Ownership 3.0 Adjacent Fields 4.0 Regional Geology 5.0 Geophysics 5.1 Data Control 5.2 Seismic-well Correlation 5.3 Horizon Interpretation 5.4 Fault Interpretation 5.5 Depth Conversion 5.6 AVO Attributes 6.0 Petrophysics 6.1 Log Data Processing

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J:\TAG Oil - 70639 - Kaheru Audit\Report\Kaheru\Summary.doc


6.2 Cutoffs for Net Pay Determination 6.3 Discussion of Results 7.0 Probabilistic Resource Assessment 7.1 Methodology 7.2 Resource Assessment Parameters 7.2.1 Area 7.2.2 Gross Pay 7.2.3 Net to Gross Ratio 7.2.4 Porosity 7.2.5 Water Saturation 7.2.6 Formation Volume Factor 7.2.7 Trap Geometry Correction Factor 7.2.8 Recovery Factor 7.3 Resource Classification 8.0 Risk Analysis 9.0 References Figures Figure 1 PEP 52181 Location Map Figure 2 Regional Geology Map of Taranaki Basin Figure 3 Kaheru Prospect Location and Adjacent Fields Figure 4 Taranaki Basin Stratigraphy Figure 5 Synthetic Seismogram of Rimu A1 Well Figure 6 Well-seismic Tie from Toru-1 into the Kaheru 3D Figure 7 The Tie Between 2D Vintages and 3D Vintage Figure 8 Map View of Kaheru Channel Picks Figure 9 Map View of Mid-Oligocene Picks Figure 10 Map View of Intra-Cretaceous Picks Figure 11 Faults Identified on Azimuth Attribute for Kaheru Channel/Kauri

Sand Surface Figure 12 Faults Identified on Azimuth Attribute for Intra-Cretaceous

Surface Figure 13 3D Perspective View from SW of Fault Framework and Seismic

Lines Figure 14 3D Perspective View from SW of Fault Framework and Kaheru

Channel Time Structure Figure 15 Channel Shape Shown on the Flattened Dip Line Figure 16 RMS Amplitude on Kaheru Channel/Kauri Sand

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Figure 17 DHI’s Shown on the Seismic Section Figure 18 DHI’s Shown on the Seismic Section Figure 19 DHI’s Shown on the Seismic Section Figure 20 DHI Conformance to the Time Structure of Kaheru Channel

/Kauri Sand Figure 21 DHI Conformance to the Time Structure of Mid-Oligocene

(proxy for Tariki Sand) Figure 22 DHI Conformance to the Time Structure of Intra-Cretaceous

(proxy for North Cape/Rakopi) Figure 23 Depth Structure of Kaheru Channel Figure 24 Depth Structure of Mid-Oligocene Figure 25 Depth Structure of Intra-Cretaceous Figure 26 Kaheru Channel Depth Structure and Prospect Polygons Figure 27 Mid-Oligocene Depth Structure and Prospect Polygons Figure 28 Intra-Cretaceous Depth Structure and Prospect Polygons Figure 29 Rimu-A1: Tariki Sand Petrophysics Figure 30 Rimu-A1: North Cape Sand Petrophysics Figure 31 Rimu-B1: Tariki Sand Petrophysics Figure 32 Kauri-A1: Kauri Sand Petrophysics Figure 33 Kauri-A1: Tariki Sand Petrophysics Figure 34 Kauri-A4: Kauri Sand Petrophysics Figure 35 Kauri-A4ST3: Tariki Sand Petrophysics Figure 36 Kauri-E1: Kauri Sand Petrophysics Figure 37 Kauri-E2: Kauri Sand Petrophysics Figure 38 Kauri-E3: Kauri Sand Petrophysics Figure 39 Kauri-EA4 ST1: Kauri Sand Petrophysics Figure 40 Kauri-E4 ST2: Tariki Sand Petrophysics Figure 41 Kauri-E6: Kauri Sand Petrophysics Figure 42 Kauri-E6: Tariki Sand Petrophysics Figure 43 Kauri-E7: Kauri Sand Petrophysics Appendices Appendix A Resource Definitions Appendix B Abbreviations, Units and Conversion Factors

Introduction — Page 1

Introduction This report was prepared by Sproule International Limited (“Sproule”) at the request of Mr. Carey Davis, Chief Executive Officer, TAG Oil Limited. TAG Oil Limited is hereinafter referred to as "the Company." The effective date of this report is May 31, 2011. The report consists of an evaluation of the oil and gas resource potential associated with the Company's interests in the Permit PEP 52181, located in the offshore Taranaki Basin of New Zealand (Figure 1). This report was prepared for the purpose of evaluating the Company’s oil and gas resource potential according to Canadian Oil and Gas Evaluation Handbook (COGEH) reserve definitions, which are consistent with the standards of National Instrument 51-101. This report was prepared for the Company’s corporate purposes. This report consists of an Introduction, Summary, Discussion and Appendices. The Introduction contains a summary of evaluation standards and procedures and pertinent author certificates, the Summary contains high-level summaries of the evaluation, and the Discussion contains general commentaries pertaining to the evaluation of the oil and gas resource potential. Resource 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. The relevant engineering data were made available by the Company or obtained from public sources and non-confidential files at Sproule. No material information regarding the reserves evaluation would have been obtained by an on-site visit. Historical Data, Interests and Burdens 1. All well data, seismic 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.

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Evaluation Standards This report has been prepared by qualified evaluators and auditors of 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 Canadian Oil and Gas Evaluation (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 In the assessment of this unproved property, all available pertinent factors were considered, including, where applicable, geological structures, prospective zones, historical drilling and production results, accessibility, access to infrastructure and markets, and geological risks. Estimates of prospective resources have been made, but economics have not been generated, and net present values of the prospects have not been included in this report. The resource classification methodology used herein complies with the COGE Handbook definitions and guidelines, in accordance with the requirements of National Instrument 51-101. Evaluation Results 1. The accuracy of resource estimates 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 performance subsequent to the date of the estimates may necessitate revision. These revisions may be material.

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BOE Cautionary Statement BOEs (or McfGEs or other applicable equivalent units) 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 equivalence at the wellhead. Forward-Looking Statements This report may contain forward-looking statements, including expectations of future production revenues and capital expenditures. Information concerning resources may also be deemed to be forward-looking, as estimates involve the implied assessment that the resources described can be profitably produced in the 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 industry (i.e., corporate commitment; regulatory approval; 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 Limited. 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 International Limited, and without the complete contents of the report being made available to that party.

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Certification Report Preparation The report entitled “Resource Assessment of the Kaheru Prospect in the Permit PEP 52181, Taranaki Basin, New Zealand (As of May 31, 2011), for TAG OIL Limited” was prepared by the following Sproule personnel:

________________________________ Barrie F. Jose, P.Geoph. Manager, Geoscience and Partner Project Leader _22_/_07_/ 2011 dd/mm/yyyy Original Signed by Alexey Romanov, Ph.D., M.Sc. ________________________________ Alexey Romanov, Ph.D., M.Sc. Geological Reservoir Simulation Specialist and Associate _22_/_07_/ 2011 dd/mm/yyyy Original Signed by Suryanarayana Karri, P.Geoph. _______________________________ Suryanarayana Karri, P.Geoph. Senior Petrophysicist and Partner _22_/_07_/ 2011 dd/mm/yyyy

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Original Signed by John L. Chipperfield, P.Geol. on behalf of Barrie F. Jose, P.Geoph.


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

________________________________ Douglas J. Carsted, P.Geol. Vice-President, Geoscience and Director _22_/_07_/ 2011 dd/mm/yyyy

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.

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Original Signed by Douglas J. Carsted, P.Geol.


Certificate

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

I, Barrie F. Jose, Manager, Geoscience, and Partner 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 reserves evaluator and reserves auditor as defined in National

Instrument 51-101. 5. My contribution to the report entitled “Resource Assessment of the Kaheru Prospect in

the Permit PEP 52181, Taranaki Basin, New Zealand (As of May 31, 2011), for TAG OIL Limited” 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 Silverstone Energy Limited.

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

Barrie F. Jose, P.Geoph.

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Certificate

Alexey Romanov, M.Sc., Ph.D.

I, Alexey Romanov, Geological Reservoir Simulation Specialist and Associate of Sproule, 900, 140 Fourth Ave SW, Calgary, Alberta, declare the following: 1. I hold the following degrees: a. Ph.D. Eng., (2007), Kazan State Technological University, Kazan, Russia

b. M.Sc. Reservoir Evaluation and Management (2004), Heriot-Watt University, Edinburgh, UK

c. M.Sc. (Honours), Petroleum Geology (2003), Kazan State Technological University, Kazan,

Russia

2. I am a member of the following professional organization:

a. Society of Petroleum Engineers (SPE)

b. Canadian Society of Petroleum Geologists (CSPG)

3. I am an applicant of the following professional organization:

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

4. My contribution to the report entitled “Resource Assessment of the Kaheru Prospect in

the Permit PEP 52181, Taranaki Basin, New Zealand (As of May 31, 2011), for TAG OIL Limited” 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. I did not undertake a field inspection of the properties.


indirect, in the properties described in the above-named report or in the securities of Remora Energy International, L.P.

Original Signed by Alexey Romanov, M.Sc., Ph.D.

Alexey Romanov, M.Sc., Ph.D.

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Certificate

Suryanarayana Karri, M.Sc., P.Geoph.

I, Suryanarayana Karri, Senior Petrophysicist and Partner of Sproule, 900, 140 Fourth Ave SW, Calgary, Alberta, declare the following: 1. I hold the following degrees: a. M.Sc. Engineering Physics and Instrumentation (1983), Osmania University, Hyderabad, India

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. Society of Petroleum Engineers (SPE) c. The Society of Petrophysicists and Well Log Analysts (SPWLA) d. Canadian Well Logging Society (CWLS) 4. My contribution to the report entitled “Resource Assessment of the Kaheru Prospect in

the Permit PEP 52181, Taranaki Basin, New Zealand (As of May 31, 2011), for TAG OIL Limited” 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. I did not undertake a field inspection of the properties.


indirect, in the properties described in the above-named report or in the securities of Remora Energy International, L.P.

Original Signed by Suryanarayana Karri, P.Geoph.

Suryanarayana Karri, P.Geoph.

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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 reserves evaluator and reserves auditor as defined in National

Instrument 51-101. 5. My contribution to the report entitled “Resource Assessment of the Kaheru Prospect in

the Permit PEP 52181, Taranaki Basin, New Zealand (As of May 31, 2011), for TAG OIL Limited” 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.


indirect, in the properties described in the above-named report or in the securities of Silverstone Energy Limited.

Douglas J. Carsted, P.Geol.

Original Signed by Douglas J. Carsted, P.Geol.

Summary — Page 1

Summary Petroleum Exploration Permit (PEP) 52181, which contains the Kaheru prospect, has extensive 2D and 3D seismic coverage, and has been identified to have high-impact exploration potential with a good chance for success. Kaheru is a Miocene-aged prospect on the same successful thrust belt play fairway as many significant Taranaki oil and gas fields, including Rimu, Kauri and Manutahi, which are immediately north of the prospect, as well as the Tariki, Ahuroa, Waihapa and Ngaere fields, which are further north. Immediately to the west, the large Kupe Gas-Condensate field is now also in full production. PEP 52181 was originally granted, as PEP 38495, to Swift Energy New Zealand Limited (“Swift”) on April 29, 2005. On May 27, 2005, Swift transferred 50 percent of its equity to Mighty River Power Limited. On June 13, 2008, Swift’s interest in the permit and operatorship was transferred to Origin Energy Resources NZ (SPV1) Ltd (Origin). Following three area amendments, the current PEP 52181 covers 171.5 km2. On December 10, 2010, Roc Oil (New Zealand) Limited (Operator) (50 percent of PEP52181), TAG OIL Limited ( 20 percent), L&M Energy Limited (15 percent) and Mosaic Oil NL (15 percent) formed a joint venture to explore the Kaheru prospect within PEP52181. This report is based on interpretations of technical data including seismic data, geological maps, well logs, well tests, cross-sections and other information supplied by the Company, obtained from published information or based on our knowledge of the economics of oil and gas exploration, development and production within the offshore Taranaki Basin, New Zealand. No proved, probable or possible reserves have been assigned to these lands at this time and they have been assessed as unproved properties containing prospective resources. Table S-1 presents the summary of the gross undiscovered petroleum initially-in-place and the gross prospective resources by prospect. These volumes have not been risked for chance of success. Table S-2 presents the summary of the Company net undiscovered petroleum initially-in-place (20 percent) and the gross prospective resources by prospect. These volumes have not been risked for chance of success. Only the mean values have been summed to show the total of the four prospective zones.

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Summary — Page 2

Table S-1

Gross Undiscovered In-Place and Prospective Resources (Unrisked)1,2, Kaheru Prospect, Taranaki Basin, New Zealand

(As of May 31, 2011)

Resources

Category

Zone

Prospect / Lead

Low 3

Estimate

(P90)

(MMboe)

Best 4

Estimate

(P50)

(MMboe)

High 5

Estimate

(P10)

(MMboe)

Mean Estimate

(MMboe)

Kauri Block 1 0.9 3.8 13.2 5.8 Kauri Block 2&3 3.1 11.8 37.5 17.2

Tariki 2.9 12.9 43.0 19.6

Undiscovered

Petroleum

Initially-In-

Place

(Unrisked) North Cape

3.8 14.9 43.8 20.6

Arithmetic

Sum

63.3


Tariki 1.4 6.4 21.5 9.8

Prospective

Resources

(Unrisked) North Cape 1.8 7.3 22.1 10.3

Arithmetic

Sum6 31.6

1. Undiscovered petroleum initially-in-place (equivalent to undiscovered resources) is that quantity of petroleum estimated, on a

given date, to be contained in accumulations yet to be discovered.

2. Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from

undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance

of discovery (geological chance of success) and a chance of development (economic, regulatory, market and facility, corporate

commitment and political risks). The chance of commerciality is the product of these two risk components. These estimates have

not been risked for either chance of discovery or chance of development. There is no certainty that any portion of the prospective

resources will be discovered and, if discovered, there is no certainty that it will be developed or, if it is developed, there is no

certainty as to either the timing of such development or whether it will be commercially viable to produce any portion of the

resources.

3. Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be discovered or recovered

from the accumulation. If probabilistic methods are used, this term reflects a P90 confidence level.

4. Best Estimate: This is considered to be the best estimate of the quantity that will actually be discovered or recovered from the

accumulation. If probabilistic methods are used, this term is a measure of central tendency of the uncertainty distribution (most

likely/mode, P50/median, or arithmetic average/mean).

5. High Estimate: This is considered to be an optimistic estimate of the quantity that will be discovered or recovered from the

accumulation. If probabilistic methods are used, this term reflects a P10 confidence level.

6. It is only appropriate to sum the mean values of the various prospects.

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Summary — Page 3

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Table S-2

Company Net Undiscovered In-Place and Prospective Resources (Unrisked)1,2,

Kaheru Prospect, Taranaki Basin, New Zealand (As of May 31, 2011)

Resources

Category

Zone

Prospect / Lead

Low 3

Estimate

(P90)

(MMboe)

Best 4

Estimate

(P50)

(MMboe)

High 5

Estimate

(P10)

(MMboe)

Mean Estimate

(MMboe)


Tariki 0.6 2.6 8.6 3.9

Undiscovered

Petroleum

Initially-In-

Place


0.8 3.0 8.8 4.1

Arithmetic

Sum 12.6


Tariki 0.3 1.3 4.3 2.0

Prospective

Resources


Arithmetic

Sum6 6.3










resources.









Discussion — Page 1

Discussion

1.0 General Permit PEP 52181 is located in the southeast corner of the south Taranaki Basin (Figure 1), approximately 8 km from shore. The permit covers 171.5 km2 in the main Taranaki oil and gas discovery fairway and is adjacent to the Rimu oil and gas field and the Kauri gas/condensate field (Figure 2). Within the permit is the Kaheru prospect, which has multiple potential reservoir targets. The area including PEP 52181 has been actively explored since the mid-1960s. Various operators have acquired fourteen 2D lines and one 3D seismic survey that cover the area of the permit. No wells have been drilled within the present boundary of PEP 52181. However, the block is along strike from the onshore Kauri, Manutahi and Rimu fields. 2.0 Ownership The permit is operated by a subsidiary of Australian-based Roc Oil Limited. TAG Oil Ltd. acquired a 20 percent interest in offshore exploration permit PEP 52181 on December 10, 2010. Participating interests in PEP 52181 (Kaheru) are Roc Oil (New Zealand) Limited (Operator) (50 percent), TAG Oil Limited (20 percent), L&M Energy Limited (15 percent) and Mosaic Oil NL (15 percent). Under the current work program for PEP 52181, the participating interests must either drill an exploration well to test the Kaheru structure in the third year or surrender the 171.5 km2 near-shore permit. 3.0 Adjacent Fields The Rimu Field is located in PMP38151 and was discovered by Swift in 1999, when the Rimu-A1 well tested 700 bopd (41o API) and 2 MMcfpd gas from the Oligocene Tariki sandstone. The reservoir depth is around 3,500 mSS. The Rimu trap is a structural closure on an imbricate fault slice called the upper plate, which is between the Rimu and Taranaki thrust faults. Hydrocarbons have also been recovered from the Tariki Sandstone in the lower plate to the west of the Rimu Fault. Production from the upper plate reservoirs began in April 2002. There has been no production from the lower plate.

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The Manutahi Field is located in PMP38155 and was discovered in 2001 by the Kauri-A1 well. Production began in September 2001. The field produces under-saturated (GOR: 172 scf/bbl), heavy (13-18o API) oil from the Pliocene Manutahi Sandstone at depths of around 1,100 mSS. The oil is trapped in a fault-bounded closure draped over the Murihiku basement uplift on the upthrown side of the Taranaki Fault. The combination of a heavy, viscous oil and a shallow, unconsolidated reservoir causes significant sand production issues. The Kauri Field is located in PMP38155 and was discovered in 2001 by the Kauri-A4 well. The initial discovery was oil in the Tariki sandstone, but subsequent production has come from the younger Kauri sandstone. With only a few exceptions, fracture stimulation is required to achieve commercial flow rates from the Kauri sandstone. The Kauri trap is another “upper plate” structural closure to the south of the Rimu Field. Production commenced in October 2002. The three fields’ cumulative production to the end of 2009 was just 21.5 bcf of gas and 1.5 MMbbl of oil and natural gas liquids. Production has been hampered by poor reservoir performance and mechanical problems. 4.0 Regional Geology The major structural features of the Permit PEP52181 are the north-south trending Manaia Fault and anticline in the west and the north-south trending Taranaki Fault zone and basement uplift in the east (Figures 2 and 3). Relative movement on these two faults has controlled the geological history of the area, ranging from Late Cretaceous to Paleocene extension and Mid-Oligocene to Late Miocene structural inversion. The Kaheru structure is situated on the Taranaki Fault trend, which extends from onshore to offshore. The Taranaki Fault, along with other compression-related thrust faults, complicates fault interpretation. There are multiple options for the fault positioning due to the poor seismic image over the eastern area of the seismic survey, although there is sufficient regional geological evidence to show the existence of the Taranaki Fault within the trend. The stratigraphy of the area is summarized in Figure 4. The main reservoir targets which are considered in this resource evaluation include the Kauri, Tariki, Rakopi and North Cape sandstones.

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Kauri Sand The Kauri Sand was penetrated by the Kauri-A4 well in the Kauri Field. It is uncertain if the age of the Kauri Sand is equivalent to the Tikoranqi Limestone. The seismic-well tie from well Toru-1 is based on a sub-regional Tikorangi Limestone (Oligocene to Early Miocene) reflector, and it indicates a close age relationship between the Tikorangi and the Kaheru channel feature. The seismic amplitude map and the AVO attributes suggest that it is a channel cut and filled on the Early Miocene shelf margin and north facing slope. Tariki Formation The Tariki Sandstone Member forms most of the Lower Otaraoa Formation beneath the eastern Taranaki Peninsula. The sandstone is comprised mainly of interbeds of fine- to coarse-grained sandstone, calcareous mudstone and limestone. The Tariki Sandstone reaches its highest sand content and maximum thickness of about 200 m in the Tariki and Ahuroa fields, where it forms the main reservoir. It has porosities of up to 23 percent, but with variable permeabilities. The sandstone is also a reservoir in the Rimu Field in the southeastern peninsula, where the formation is thicker but less sandy. The sandstone here is interpreted as being deposited in a submarine fan system. In sustained testing of the Rimu discovery well, it produced 44oAPI oil at rates of up to 1,525 bbl/d and 4.8 MMcfpd on a 1/2” choke. In the Kauri-A1 well, a 34oAPI oil was produced from a zone with measured porosity of up to 22 percent and 180 mD permeability. Rakopi Formation and North Cape Formation The Rakopi Formation is the oldest syn-rift Late Cretaceous formation with reservoir potential in the basin. This terrestrial unit has been intersected in six wells in which core porosities of up to 20 percent, permeabilities of up to 16 mD and sand ratios of more than 60 percent have been recorded. The formation is well bedded and contains numerous shale beds, which should provide good intra-formational seals. The North Cape Formation overlies the Rakopi Formation and is a predominantly massive, marine, sandy unit of latest Cretaceous age. The formation has measured porosities of up to 26 percent and permeabilities of over 500 mD. Although largely untested, the reservoir potential of the North Cape Formation is good.

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5.0 Geophysics The objective of the geophysical review was to assess the validity of the seismic interpretation of the horizons, faults and AVO and the impact of the interpretation uncertainties on the closure areas. 5.1 Data Control The Kaheru 3D was acquired by Swift to explore the offshore extension of the Rimu-Kauri trend. Multiple seismic volumes were provided for this audit:

• CGG PSTM processed in Q1-Q2, 2006 • CGG PSDM processed in Q4, 2006 • TGS PSDM processed in March, 2008 • Emerald PSTM full angle processed in Q1, 2007 • Emerald PSTM far angle processed in Q1, 2007 • Emerald PSTM near angle processed in Q1, 2007 • Emerald Vp/Vs attribute

Outside of the Kaheru 3D area, the latest processed version of twenty-three 2D seismic lines were supplied by the Company to provide regional context for the mapping and interpretation of Kaheru Channel horizon. The Kaheru 3D, coupled with additional 2D lines, provided a reasonable framework to assess the structure and hydrocarbon potential of PEP 52181. All of the above seismic volumes were loaded into Petrel together with the following main horizons:

• Base Matemateaonga Formation unconformity, Early Pliocene • Tikorangi Formation – Kaheru Channel, Early Miocene • Mid-Oligocene Unconformity • Intra-Cretaceous

Fault sticks in time, which include the Taranaki Fault, were supplied by the Company. Fault polygons at the Kaheru Channel level were also provided. A total of 10 wells from the adjacent fields (Kauri [4], Rimu [2], Kupe[3] and Toru [1]) were loaded into Petrel for velocity analysis. The recently granted PEP52181 boundary was also loaded into Petrel.

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All of the data for the project are referenced to a “New Zealand Map Grid (NZMG) with Geodetic Datum 1949”. 5.2 Seismic-well Correlation Although there are no wells drilled into the Kaheru prospect, wells and 2D seismic lines are available over the Rimu and Kauri fields to the north. Sproule generated a synthetic for the Rimu A1 well, which provides a fair to poor tie with the seismic (Figure 5). Another way to perform the seismic-well tie is to investigate the regional correlation along 2D seismic lines through the Toru-1 well to the west and the Kaheru 3D (Figure 6). Generally, the correlation of horizons on the Emerald PSTM 3D and 2D is reasonable (Figure 7). 5.3 Horizon Interpretation The Emerald noise reduction processing did improve signal to noise levels, but at the cost of vertical resolution, which was poorer than in the original CGG processing. The Emerald PSTM 3D shows better continuity and a higher signal-noise ratio. The structural definition has been substantially improved over the eastern flank of the structure. Reverberation noise and multiples caused by the Taranaki thrust fault were effectively suppressed. However, the velocity model-driven processing may be imprinted upon the processed seismic imaging. Initially, the CGG PSTM 3D was used for interpretation. Emerald Geoscience Research reprocessed the CGG volume and improved imaging quality over the eastern flank. Accordingly, the horizon interpretation was carried out on Emerald reprocessed data. The horizon picks supplied by the Company appear to match the Emerald PSTM volume. The interpretation confidence of these horizon picks is high within the western foredeep and decreases eastwards due to the poorer imaging on the crest of the structure. On the Emerald PSTM 3D, the Tikoranqi/Kaheru Channel is characterized by a sub-regionally continuous amplitude peak. The horizons supplied by the Company from the interpretation appear reasonable, but the structure lacks closure on the 3D seismic, and it is fundamental to incorporate the 2D seismic to extend the mapping northwards. After receiving the additional 2D lines over the Rimu and Kauri fields, Sproule extended the Kaheru Channel interpretation to the north (Figures 7 and 8), which provided the regional context for mapping the closure at the Kaheru Channel horizon (Figure 23). Sproule independently interpreted the fault framework over the Kaheru prospect area and the Rimu and Kauri fields. Over the whole area including the Kaheru, Rimu and Kauri areas,

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three N-S trending faults divide the whole structure into three compartments: Block 1, Block 2 and Block 3 (Figures 13, 14, 23). The Tariki sandstones lack a strong or continuous seismic reflection on the Emerald PSTM 3D, so the Mid-Oligocene Unconformity marker has been used as a proxy for the Tariki Sandstone. On the 3D seismic, the Intra-Cretaceous has been used as a proxy for potential reservoir objectives in the North Cape Formation and the Rakopi Formation. There is uncertainty in the exact position of the Rakopi relative to the intra-Cretaceous horizon, but it is assumed to be structurally conformable with the Intra-Cretaceous map. The North Cape and Rakopi formations occur sporadically in wells along the eastern margin and include potential reservoir sands, but production has not been established. Figures 8, 9 and 10 show the map view of time picks of Kaheru Channel, Mid-Oligocene and Intra-Cretaceous respectively. 5.4 Fault Interpretation Fault sticks and polygons supplied by the Company were loaded into Petrel and were compared to the Emerald PSTM 3D seismic. Sproule generated a variance attribute volume and extracted a variance attribute on Kaheru Channel and Intra-Cretaceous surfaces to audit the fault sticks supplied by the Company. Dip-Azimuth and Dip-Angle surface attributes were also generated to show the changes in dip attitude and direction of the horizon not readily apparent on the time structure surface alone. Using the Azimuth attributes seen on the Kaheru Channel and Intra-Cretaceous horizons, Sproule independently interpreted the main Taranaki thrust fault throughout the 3D volume to improve positioning of the fault (Figures 11-13). Beside the main Taranaki thrust fault, the additional 2D lines suggest two more thrust faults. The thrust fault to the west appears to extend south into the Emerald 3D and becomes a strike-slip fault, which may serve as a fault seal to the north (Figures 11, 13 and 14). 5.5 Depth Conversion Sproule reviewed the AVO attributes supplied by the Company, which included a far angle stack, near angle stack and Vp/Vs ratio volumes derived from the pre-stack inversion. DHIs (flat spots) were also reviewed on the full stack volume at different potential reservoir levels.

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The amplitude difference on the Kaheru Channel level between the far angle and near angle stack volumes may be associated with anomalies of lithology and hydrocarbon. Secondly, the Vp/Vs ratio derived from the pre-stack inversion indicates that a lower Vp/Vs ratio may result from the presence of hydrocarbons. In addition, the RMS amplitude anomaly shown on the Kaheru Channel may relate to the channel sandstone and hydrocarbon (Figure 16). While these AVO anomalies seen in the seismic data provide some encouragement, there are insufficient direct well ties to calibrate the seismic. Strong amplitudes can be observed in the lower structures of the Mid-Oligocene and Intra-Cretaceous levels and could be due to the focusing of the ray paths. The poor image over the crest area of the Mid-Oligocene and Intra-Cretaceous prevents the use of AVO attributes and may result from structural disruptions. However, possible DHIs (flat spots) can be observed on the seismic sections, especially over the areas where strong amplitude is shown on the Kaheru Channel horizon (Figures 17-19). DHIs on these seismic sections show good conformance to the structure (Figures 20-22). Similarly, these DHIs seen on the seismic appear to be encouraging, but the direct conclusion that these DHIs are attributed to a Gas-Oil-Contact or Oil-Water-Contact cannot be made, due to the lack of well-seismic calibration. 5.6 AVO Attributes Time-depth relationships derived from the adjacent fields were used in the velocity analysis. Several different velocity models were investigated. The V=V0+K*Z method was chosen to build the final velocity model. The average velocity derived from the final velocity model agrees with analogous wells in the Rimu and Kauri fields. Figures 23, 24 and 25 show map views of the depth structures of Kaheru Channel, Mid-Oligocene and Intra-Cretaceous. Figures 26, 27 and 28 show map views of these three depth structures with prospect polygons superimposed on them. 6.0 Petrophysics Sproule conducted a petrophysical analysis for the ten key wells from the Rimu and Kauri fields adjacent to the Permit PEP 52818 using the PRIZM module in the Geographix software suite. The wells were chosen as an analogue to provide representative sampling for calculating the average reservoir parameters in the Kauri, the Tariki and the North Cape

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formations. The range of parameters values were used to construct reasonable input distributions for the probabilistic resource assessment using Monte Carlo simulation. The Rimu-A1 and Rimu-B1 wells were analysed for both the Kauri and the Tariki formations in the Rimu Field. The Kauri-A1, Kauri-A4, A4ST2, A4ST3, E1, E2, E3, E4AST1, E4AST2, E6 and E7 wells from the Kauri Field were analysed predominantly for the Kauri Sand. The Rimu-A1 well was used for the North Cape Formation. 6.1 Log Data Processing In the analysis, the volume of shale was computed using gamma ray logs. The effective porosity was calculated by correcting the apparent porosity from neutron and density logs for the estimated volume of shale within the formation. Water saturation was calculated using the modified Simandoux equation, with values of a, m and n set to 1, 2, and 2, respectively. The volume of shale was estimated from the GR log using the following equation:

1)(

)(0 <

−−

<=cleanshl

clean

GRGRGRGR

Vsh

Where, Vsh is the volume of shale, GR is the gamma ray value of the formation in API units, GRclean is the clean matrix gamma ray value, and GRshl is the gamma ray value in shale. The apparent porosity was calculated using the average of the neutron and density porosity values on a sandstone matrix corrected for the volume of shale estimated to be in the reservoir. The effective porosity (PHIE) was calculated by correcting the apparent porosity from logs for the estimated volume of shale within the formation. The neutron log was recorded on a limestone scale and was converted to sandstone units. The density porosity was calculated using the bulk density log, assuming a sandstone matrix density of 2.65 grams per cubic centimeter and a fluid density of 1.0 grams per cubic centimeter. The density porosity equation used in the analysis is as follows:

)()(

flma

bmaD ρρ

ρρφ

−−

=

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Where �ma is the Matrix Density in gm/cc, �fl is the fluid density in gm/cc, �b is the bulk density in gm/cc and �D is the Density porosity. The apparent porosity was calculated using the equation

2)( NSSD

Aφφφ +

=

where �A is the apparent porosity, �D is the density porosity and �NSS is the neutron porosity in sandstone units. The effective porosity (PHIE) was calculated by correcting for the estimated volume of shale within the formation, using the equation

)1( shAe V−=φφ where �e is the effective porosity, �A is the apparent porosity and Vsh is the volume of shale. Water saturation was calculated using the modified Simandoux equation, with values of a, m and n set to 1, 2, and 2, respectively. The Modified Simandoux equation is as follows:

)1(2

)1(4

2/12

shw

me

sh

sh

tshw

me

sh

sh

MS

VaR

RV

RVaRRV

Sw

−

⎟⎟

⎠

⎞

⎜⎜

⎝

⎛−

−+⎟⎟

⎠

⎞⎜⎜⎝

⎛

=φ

φ

Where SwMS is the water saturation, �e is the effective porosity, Rt is the true formation resistivity in ohmm, Vsh is the volume of shale, “a” is the Archie constant, “m” is the cementation factor, “n” is the saturation exponent, Rw is the formation water resistivity and Rsh is the resistivity of shale. The deep resistivity log was assumed to be the true formation resistivity (Rt). A value of 0.1 ohm-m was used for formation water resistivity (Rw).

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6.2 Cutoffs for Net Pay Determination The net pay intervals were defined using an effective porosity cutoff > 10 percent, a volume of shale cutoff < 40 percent, and a water saturation cutoff of 60 percent. 6.3 Discussion of Results The Kauri Sand, which is predominantly sandstone with siltstone and claystone interbeds, has a gross thickness ranging from 100 to 465 metres. It has a net pay thickness of 5 to 25 metres with an effective porosity range of 12 to 20 percent and a water saturation of 38 to 60 percent. In the Kauri Field, this is the main hydrocarbon-producing formation. The Tariki Formation consists of claystone and interbedded sandstone. In most of the wells analyzed, gas and oil shows were reported. The gross thickness of the formation varies from 8 to 55 metres. The net pay thickness ranges from 5 to 35 metres with an effective porosity range of 13 to 21 percent and a water saturation of 40 to 60 percent. The Tariki Formation tested hydrocarbons in Rimu Field. The North Cape Formation encountered in well Rimu-A1 consists of sandstone interbedded with claystone. It has a gross thickness of 66 metres. The net pay thickness is 4 metres with an effective porosity of 11 percent and an average water saturation of 45 percent. The tested interval between 4,462 and 4,472 metres produced only water. Figures 29 through 43 show the petrophysical evaluation results for the analysed formations in wells. 7.0 Probabilistic Resource Assessment 7.1 Methodology No reserves or contingent resources have been assigned to Kaheru Area, and it has been assessed as an unproved property. Several wells drilled in the vicinity of the Area have been used to estimate a range of reservoir parameters. Sproule has estimated the undiscovered initially-in-place volumes and applied a recovery factor distribution to estimate the unrisked prospective resources, as shown in Table D-1 for the gross volumes (100 percent) and Table D-2 for the Company net volumes

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(20 percent). These volumes have been estimated at various levels of certainty, and include a low estimate (P90), a best estimate (P50), a high estimate (P10) and a mean estimate. This assessment was made using a Monte Carlo simulation of input parameter distributions, assuming that the undiscovered hydrocarbon will be gas converted to BOE to reflect the uncertainty in the hydrocarbon type. There remains some uncertainty in the structure mapping at the Kaheru level, as the prospect is only partially constrained by 3D seismic data and the crest of the structure lies to the north under 2D seismic coverage (Figure 8). The Mid-Oligocene (Tariki sand) and Intra-Cretaceous (North Cape/Rakopi) levels are, however, entirely constrained by the 3D seismic. The areas and calculated gross rock volumes of the prospects are not the major uncertainty in the estimation of the initially in-place and the prospective resources (Tables D-1 and D-2). The reservoir parameters used in the volumetric estimate are more uncertain and are constrained by limited data and published analogue information (porosity, net-gross, formation volume factor and recovery factor), especially for the North Cape zone. Sproule built a Monte-Carlo simulation model for these prospects based on the resource assessment parameters discussed in the following section. 7.2 Resource Assessment Parameters 7.2.1 Area The estimates of area were calculated within Petrel for each of the zones. For the Kauri Block 1 prospect, the area distribution is based on P50 and P10 contour levels as shown in Figure 26. For the Kauri Block 2&3 and Tariki prospects, the area distribution is based on P50 and P10 contour levels as shown in Figure 27. For the North Cape prospect, the area distribution is based on P50 and P05 contour levels as shown in Figure 28. A lognormal distribution was generated within GeoX utilizing the areas with given probabilities as input parameters. The area parameter is reasonably well constrained by spill points. 7.2.2 Gross Pay The gross pay distributions are based on well data from the Rimu and the Kauri fields in the vicinity of the Kaheru Area. Normally distributed values ranging from 50 to 100 metres for Tariki and North Cape were used in the analysis. For the Kauri sandstone reservoir, net pay values were directly used in the analysis. The net pay thickness values range from 5 to 30 metres.

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7.2.3 Net-to-Gross Ratio Normal distributions of 10 to 84 percent for Tariki and North Cape were used in the analysis, based on the available regional analogues. Since net pay thickness values were used to model the Kauri sandstone reservoir, a net-to-gross ratio was not used. 7.2.4 Porosity The porosity distributions were based on the petrophysical evaluation. Normal distributions with a range of 12 to 20 percent for Kauri, 11 to 25 percent for Tariki and 11 to 17 percent for North Cape were used. 7.2.5 Water Saturation For water saturation, normal distribution ranges of 38 to 60 percent for Kauri and 40 to 60 percent for the Tariki and North Cape formations were used. 7.2.6 Formation Volume Factor The gas expansion factor normal distribution with range of 240-270 scf/rcf was used in the assessment. This range was identified using available public information for other accumulations near the Kaheru Area. 7.2.7 Trap Geometry Correction Factor The “edge effect correction” factor was developed from trap geometry and reservoir thicknesses. Considering high trap relief, in comparison to the column height and reservoir thickness, a uniform distribution of 0.8-1.0 was utilized. 7.2.8 Recovery Factor The recovery factor distributions were based on size of accumulation, reservoir quality and continuity, expected pay thicknesses, expected oil quality, presence of regional aquifers, and data from analogous fields. The recovery factors were specified as normal distribution of 40-60 percent.

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7.3 Resource Classification Appendix B contains the resource definitions from the COGE Handbook which were used in the independent assessment of Kaheru Area. Given that none of the structures identified on seismic have been drilled, the resources attributed to the structures are classified as undiscovered. Undiscovered petroleum initially-in-place (equivalent to undiscovered resources) is defined as those quantities of oil and gas estimated on a given date to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially-in-place is referred to as prospective resources, the remainder as unrecoverable. The prospects were evaluated using probabilistic methods. The undiscovered petroleum initially-in-place and prospective resources were estimated volumetrically for the North Cape/Rakopi, Tariki, and Kaheru sands using probabilistic models developed and aggregated in GeoX. The unrisked distribution for each of the prospects are presented in Tables D-1 and D-2 as the low, best and high estimates; the mean estimate is the average of all the outcomes. The mean values are the only ones that can be arithmetically summed for a portfolio of prospects. When assessing resources, Sproule conforms to COGEH guidelines by providing three estimates to reflect the uncertainty associated with the assessment of the prospects, as follows: Low Estimate: This is considered to be a conservative estimate of the quantity that

will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

Best Estimate: This is considered to be the best estimate of the quantity that will

actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

High Estimate: This is considered to be an optimistic estimate of the quantity that will

actually be recovered. It is unlikely that the actual remaining

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quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

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Table D-1

Gross Undiscovered In-Place and Prospective Resources (Unrisked)1,2, Kaheru Prospect, Taranaki Basin, New Zealand

(As of May 31, 2011)

Resources

Category

Zone

Prospect / Lead

Low 3

Estimate

(P90)

(MMboe)

Best 4

Estimate

(P50)

(MMboe)

High 5

Estimate

(P10)

(MMboe)

Mean Estimate

(MMboe)


Tariki 2.9 12.9 43.0 19.6

Undiscovered

Petroleum

Initially-In-

Place


3.8 14.9 43.8 20.6

Arithmetic

Sum

63.3


Tariki 1.4 6.4 21.5 9.8

Prospective

Resources


Arithmetic

Sum6 31.6










resources.









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Table D-2

Company Net Undiscovered In-Place and Prospective Resources (Unrisked)1,2,

Kaheru Prospect, Taranaki Basin, New Zealand (As of May 31, 2011)

Resources

Category

Zone

Prospect / Lead

Low 3

Estimate

(P90)

(MMboe)

Best 4

Estimate

(P50)

(MMboe)

High 5

Estimate

(P10)

(MMboe)

Mean Estimate

(MMboe)


Tariki 0.6 2.6 8.6 3.9

Undiscovered

Petroleum

Initially-In-

Place


0.8 3.0 8.8 4.1

Arithmetic

Sum 12.6


Tariki 0.3 1.3 4.3 2.0

Prospective

Resources


Arithmetic

Sum6 6.3










resources.









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3219.70639.


8.0 Risk Analysis The Kaheru prospect has a very low source and charge risk. The hydrocarbons tested at the Rimu, Kauri, Manutahi and Kupe South Fields prove the presence of a petroleum system. The relative timing of trap formation and hydrocarbon charge should be identical to Rimu and Kauri fields. The trap at Kaheru is a continuation of the trap geometry that has been successfully tested at the Rimu and Kauri fields along strike to the north. The main trap risk on the Kaheru Channel level is the fault seal associated with strike-slip fault to the north. Also, the formation disruption associated with the thrust fault may undermine the top seal. The AVO anomalies (difference between far angle and near angle, Vp/Vs ratio, amplitude anomaly and DHIs) shown on the seismic data suggest the potential for oil and gas accumulation although the AVO analysis lacks well-seismic calibration. Future work may be focused on the understanding the seismic response with offset for the type wells in Rimu and Kauri fields. Fluid substitution analysis may also be helpful to understand the fluid contribution to the seismic response. 9.0 References New Zealand Petroleum Basins, Crown Minerals (2010) www.crownminerals.govt.nz/cms/pdf-library/petroleum-publications-1/2010%20NZ%20Petroleum%20Basin%20Report-WEB.pdf. New Zealand government website (n.d.) taranaki_reservoirs.pdf. Origin (2009) PEP38495 Seismic Interpretation and Prospectivity Report Offshore Taranaki, New Zealand. Geosphere (2007) 3D Seismic Interpretation Report of Kaheru Prospect Southern Offshore Taranaki Basin (PEP 38495).

Figure 170639

PEP 52181 Location Map

Source: http://www.crownminerals.govt.nz

PEP 52181

Figure 2

70639

Regional Geology Map of Taranaki Basin

Source: http://www.crownminerals.govt.nz

Figure 370639

Kaheru Prospect Location and Adjacent Fields

Source: Kaheru Form-in Presentation, Mightyriver Power, September, 2007

Figure 470639

Taranaki Basin Stratigraphy

Source: Kaheru Form-in Presentation, Mightyriver Power, September, 2007

Figure 570639

Synthetic Seismogram of Rimu A1 Well

Figure 670639

Well-seismic Tie from Toru-1 into the Kaheru 3D

Source: 3D Seismic interpretation Report, GeoSphere, April, 2007

Figure 770639

3D Perspective View from the West of the Tie Between 2D Vintages and 3D Vintage

3D Seismic

Time Surface of Kaheru Channel

Figure 8

70639

Map View of Kaheru Channel Picks (2D and 3D)

Lease Boundary

Figure 970639

Map View of Mid-Oligocene Picks

Lease Boundary

Figure 1

070639

Map View of Intra-Cretaceous Picks

Lease Boundary

Figure 1

170639

Faults Identified on Azimuth Attribute for Kaheru Channel/Kauri Sand Surface

Strike-slip Fault

Figure 1

270639

Faults Identified on Azimuth Attribute for Intra-Cretaceous Surface

Figure 1

370639

3D Perspective View from SW of Fault Framework and Seismic Lines

Figure 1

470639

3D Perspective View from SW of Fault Framework and Kaheru Channel Time Structure

Figure 1

570639

Channel Shape Shown on the Flattened Dip Line

Channel Shape Shown on the Dip Line

Figure 1

670639

RMS Amplitude on Kaheru Channel/Kauri Sand

Amplitude Anomaly Probably Associated with Kaheru Channel

Figure 1

770639

DHI’s Shown on the Seismic Section

DHI-Flat Spot

Figure 1

870639


DHI-Flat Spot

Figure 1

970639


DHI-Flat Spot

Figure 2

070639

DHI Conformance to the Time Structure of Kaheru Channel/Kauri Sand

DHI Picks beneath Kaheru Channel Horizon

Figure 2

170639

DHI Conformance to the Time Structure of Mid-Oligocene (proxy for Tariki Sand)

DHI Picks beneath Mid-Oligocene Horizon

Figure 2

270639

DHI Conformance to the Time Structure of Intra-Cretaceous (proxy for North Cape/Rakopi)

DHI Picks beneath Intra-Cretaceous Horizon

Figure 23

70639

Depth Structure of Kaheru Channel Depth Structure (2D and 3D)

Lease Boundary

Block 1

Block 2

Block 3

Figure 2

470639

Depth Structure of Mid-Oligocene

Lease Boundary

Figure 2

570639

Depth Structure of Intra-Cretaceous

Lease Boundary

Figure 26

70639

Kaheru Channel Depth Structure and Prospect Polygons

Lease Boundary

P10 Case

P90 Case

Block 1

Block 2

Block 3

Figure 2

770639

Mid-Oligocene Depth Structure and Prospect Polygons

Lease BoundaryP10 Case

P90 Case

Figure 2

870639

Intra-Cretaceous Depth Structure and Prospect Polygons

Lease BoundaryP5 Case

P90 Case

Figure 29

70639

Rimu-A1: Tariki Sand Petrophysics

Figure 30

70639

Rimu-A1: North Cape Sand Petrophysics

Figure 31

70639

Rimu-B1: Tariki Sand Petrophysics

Figure 32

70639

Kauri-A1: Kauri Sand Petrophysics

Figure 33

70639

Kauri-A1: Tariki Sand Petrophysics

Figure 34

70639

Kauri-A4: Kauri Sand Petrophysics

Figure 35

70639

Kauri-A4ST3: Tariki Sand Petrophysics

Figure 36

70639

Kauri-E1: Kauri Sand Petrophysics

Figure 37

70639


Figure 38

70639


Figure 39

70639

Kauri-EA4 ST1: Kauri Sand Petrophysics

Figure 40

70639

Kauri-E4 ST2: Tariki Sand Petrophysics

Figure 41

70639


Figure 42

70639

Kauri-E6: Tariki Sand Petrophysics

Figure 43

70639


APPENDIX A

SPE / WPC RESERVES DEFINITIONS

Appendix A — Page 1

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APPENDIX A

Resource Definitions This discussion has been excerpted from Sections 5.2 and 5.3 of the Canadian Oil and Gas Evaluation Handbook, Second Edition, September, 2007. The following definitions relate to the subdivisions in the SPE-PRMS resources classification framework and use the primary nomenclature and concepts contained in the 2007 SPE-PRMS, with direct excerpts shown in italics. Total Petroleum Initially-In-Place (PIIP) is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”). Discovered Petroleum Initially-In-Place (equivalent to discovered resources) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.

Production is the cumulative quantity of petroleum that has been recovered at a given date. Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is


3219.70639.


also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. Unrecoverable is that portion of Discovered or Undiscovered PIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Undiscovered Petroleum Initially-In-Place (equivalent to undiscovered resources) is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as “prospective resources,” the remainder as “unrecoverable.”

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity.

Resource Categories Due to the high uncertainty in estimating resources, evaluations of these assets require some type of probabilistic methodology. Expected value concepts and decision tree analyses are routine; however, in high-risk, high-reward projects, Monte Carlo simulation can be used. In any event, three success cases plus a failure case should be included in the evaluation of the resources (see Section 9 of the Canadian Oil and Gas Evaluation Handbook for details on these methods). When evaluating resources, in particular, contingent and prospective resources, the following mutually exclusive categories are recommended:


3219.70639.


• Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term reflects a P90 confidence level.

• Best Estimate: This is considered to be the best estimate of the quantity that will

actually be recovered from the accumulation. If probabilistic methods are used, this term is a measure of central tendency of the uncertainty distribution (most likely/mode, P50/median, or arithmetic average/mean).

• High Estimate: This is considered to be an optimistic estimate of the quantity that

will actually be recovered from the accumulation. If probabilistic methods are used, this term reflects a P10 confidence level.

Company Gross Contingent Resources are the Company’s working interest share of the contingent resources, before deduction of any royalties. Company Net Contingent Resources are the gross contingent resources of the properties in which the Company has an interest, less all Crown, freehold, and overriding royalties and interests owned by others. 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.

APPENDIX B

ABBREVIATIONS, UNITS

AND CONVERSION FACTORS

Appendix B — Page 1

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J:\TAG Oil - 70639 - Kaheru Audit\Report\Kaheru\Appendix B - Abbrev.doc

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 Bg gas formation volume factor Bo 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 FPSO Floating Production Storage and Offloading Vessel 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


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LPG liquefied petroleum gas mD millidarcies mSS meters subsea 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 oAPI degrees API (American Petroleum Institute)


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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


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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


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 (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

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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 (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)

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resource assessment of the kaheru …...2011/08/09 · certificates summary table s-1 gross...

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