technical assessment of the undiscovered …

TECHNICAL ASSESSMENT OF THE UNDISCOVERED

HYDROCARBON RESOURCE POTENTIAL OF PEP 38348

AND 38349, ONSHORE EAST COAST BASIN, NEW ZEALAND

(As of May 31, 2008)

Copies: Trans-Orient (6 copies) Sproule International Limited (1 copy) Electronic (1) Project No.: 3738.70483 Prepared For: Trans-Orient Petroleum Ltd. Authors: Douglas J. Carsted, P.Geol., Project Leader Barrie F. Jose, P.Geoph. Suryanarayana Karri, M.Sc. Exclusivity: This report has been prepared for the exclusive use of Trans-Orient, and shall

not be reproduced, distributed, or made available to any other company or person, regulatory body, or organization without the knowledge and written consent of Sproule International Limited, and without the complete contents of the report being made available to that party.

Table of Contents — Page 1

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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 Within the text

Table of Contents — Page 2

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Figures Figure 1 Map of New Zealand Highlighting Major Onshore and Offshore

Basins Figure 2 Map of East Coast Basin New Zealand Highlighting PEP Blocks

38348 and 38349 Figure 3 Map of East Coast Basin Highlighting PEP 38348 and 38349 Figure 4 North Island, East Coast Basin, Well Location Map Figure 5 Generalized Stratigraphy of East Coast Basin New Zealand Figure 6 Generalized Stratigraphy of East Coast Basin New Zealand with

potential reservoirs, source rocks and seals Figure 7 Summary of Petroleum systems of the East Coast of New Zealand Figure 8 PEP 38348 - Leads with 2D Seismic Control and location of oil and

gas seeps Figure 9 Summary of Petroleum systems of the East Coast of New Zealand Figure 10 Leads and Prospects identified on previous permit PEP38330 Figure 11 PEP 38349 - Leads with 2D Seismic Control and location of oil and

gas seeps Figure 12 Porosity Permeability cross plot for some select outcrop samples

from the PEP Block 38348. Figure 13 Richness and Maturity of Waipawa and Whangai Source Rocks Figure 14 Comparison of Waipawa and Whanghai to North American

Analogues Appendices Appendix A Definitions Appendix B Abbreviations Appendix C Unproved Properties

Introduction — Page 1

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Introduction This report was originally prepared during September 2007 and updated in May 2008, by qualified evaluators and auditors of Sproule International Limited (“Sproule”) at the request of Dr. David Bennett, Executive Chairman of Trans-Orient Petroleum Ltd. Trans-Orient Petroleum Ltd. is hereinafter referred to as “the Company”. The effective date of this report is May 31, 2008. The report consists of a technical assessment of the undiscovered in-place hydrocarbon resources associated with the two onshore Petroleum Exploration Permit blocks (PEP 38348 and 38349) held 100 percent by the Company and situated in the East Coast Basin, New Zealand (Figure 1). Figure 2 shows the outline of the two PEP blocks. The assessment was conducted using data provided by the Company, data available in the public domain and from the non-confidential files of Sproule. The resource estimates for the two PEP Blocks are based on a probabilistic model of the expected reservoir parameters of undiscovered prospective reservoirs and traps that may be encountered within the blocks. 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 PEP 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 a 100 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 to the Company’s 100 percent working interest. This single volume report contains an Introduction, Summary and Discussion accompanied by pertinent Tables, Figures, and Appendices. The Introduction includes disclaimers 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 two PEP blocks. The definitions used in this report are in accordance with those presented in the Canadian Oil and Gas Evaluators Handbook (COGEH).


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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, 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 undiscovered resource potential have been made. Exclusivity This report has been prepared for the exclusive use of Trans-Orient Petroleum Ltd. 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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17 / 06 /2008 dd/mm/yr

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Certification Report Preparation The report entitled “Technical Assessment of the Undiscovered Hydrocarbon Resource Potential of PEP 38348 and 38349, Onshore East Coast Basin, New Zealand, As of May 31, 2008,” was prepared by the following Sproule personnel:

Original signed by D. J. Carsted ________________________________________

Douglas J. Carsted, P.Geol. Project Leader; Vice-President, Geoscience Original signed by B. F.Jose ________________________________________

Barrie F. Jose, M.Sc., P.Geoph. Chief Geophysicist Manager, Geoscience Original signed by S. Karri ________________________________________

Suryanarayana Karri, M.Sc., Senior Petrophysical Specialist


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

Original signed by J. L. Chipperfield ________________________________________

John L. Chipperfield, P.Geol. Senior Vice-President

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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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

Hydrocarbon Resource Potential of PEP 38348 and 38349, Onshore East Coast Basin, New Zealand (As of May 31, 2008),” 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 Trans-Orient Petroleum Ltd.

Original signed by D. J. Carsted Douglas J. Carsted, P.Geol.


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Certificate

Barrie F. Jose, M.Sc., P.Geoph. I, Barrie F. Jose, Manager, Geoscience, and Associate at Sproule International Limited, 900, 140 Fourth Ave SW, Calgary, Alberta, declare the following: 1. I hold the following degrees:

a. M.Sc. Geophysics (1979) University of British Columbia, Vancouver BC, Canada b. B.Sc. (Honours) Geological Science with Physics (1977) Queens University, Kingston ON,

Canada 2. I am a registered professional:

a. Professional Geophysicist (P.Geoph.) Province of Alberta, Canada 3. I am a member of the following professional organizations:

a. Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA ) b. Canadian Society of Exploration Geophysicists (CSEG) c. Society of Exploration Geophysicists (SEG) d. Canadian Society of Petroleum Geologists (CSPG) e. American Association of Petroleum Geologists (AAPG) f. Petroleum Exploration Society of Great Britain (PESGB) g. European Association of Geoscientists and Engineers (EAGE)

4. I am a qualified reserves evaluator and reserves auditor as defined in National Instrument

51-101. 5. My contribution to the report entitled “Technical Assessment of the Undiscovered

Hydrocarbon Resource Potential of PEP 38348 and 38349, Onshore East Coast Basin, New Zealand (As of May 31, 2008),” 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.



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


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Certificate

Suryanarayana Karri, M.Sc.

I, Suryanarayana Karri, Senior Petrophysicist, at Sproule International Limited, 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 member of the following professional organizations: a. Society of Petroleum Engineers (SPE) b. The Society of Petrophysicists and Well Log Analysts (SPWLA) c. Canadian Society of Petroleum Geologists (CSPG) 3. My contribution to the report entitled “Technical Assessment of the Undiscovered

Hydrocarbon Resource Potential of PEP 38348 and 38349, Onshore East Coast Basin, New Zealand (As of May 31, 2008),” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule International Limited. I did not undertake a field inspection of the properties.



Original signed by S. Karri Suryanarayana Karri, M.Sc.


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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

Hydrocarbon Resource Potential of PEP 38348 and 38349, Onshore East Coast Basin, New Zealand (As of May 31, 2008),” 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.



Original signed by J. L. Chipperfield John L. Chipperfield, P.Geol.

Summary — Page 1

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Summary This assessment 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 New Zealand. The Company has been granted two five-year exclusive petroleum exploration permits by the Government of New Zealand, covering PEP blocks 38348 and 38349, effective November 8, 2006 and expiring November 7, 2011. Both permits are located in the East Coast Basin on the North Island. The terms of both agreements are identical and are discussed later in this report. A summary of the lands held by the Company as PEP 38348 and PEP 38349 blocks, as of May 31, 2008, is presented in Table S-1.

Table S-1 Summary of Unproved Properties

PEP Blocks 38348 and 38349, New Zealand

Area Working Interest Gross Acres Net Acres

PEP Block 38348 100 % 530,535 530,535

PEP Block 38349 100 % 1,633,366 1,633,366

Total Unproved Properties 2,163,901 2,163,901 No proved, probable or possible reserves have been assigned to these holdings at this time and they have been assessed as unproved properties. Based on our assessment, it is our opinion that these permits contain Undiscovered Resources, as defined in the Canadian Oil and Gas Evaluation (COGE) Handbook:

"Undiscovered Resources are those quantities of oil and gas resources estimated on a given date to be contained in accumulations yet to be discovered.”

Summary — Page 2

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Under National Instrument (NI) 51-101, companies are permitted to disclose such 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. 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 is applicable to the undiscovered resources estimated to exist on these land holdings at this time. After reviewing the geological information related to these two permits, it is our opinion that there is an equal chance of discovering either gas or oil within the identified prospects and leads. To simplify the modeling and analysis, the structures were deemed to be oil-bearing, with the volumes reported as barrels of oil equivalent (BOE). Thus, the undiscovered hydrocarbon resources estimated to exist on the two PEP Blocks are reported as BOE in-place volumes. A summary of the gross undiscovered in-place hydrocarbon resources estimated to exist within the PEP 38348 and 38349 blocks, as of May 31, 2008, is presented in Table S-2a, as follows:

Table S-2a Summary of the Gross Undiscovered In-Place Hydrocarbon Resources

PEP Block 38348 and Block 38349, New Zealand

BOE1-in-Place (MMbbls)2

Area Low Estimate Best Estimate High Estimate

PEP 38348 615 1002 1773

PEP 38349 601 710 866

Total 3 1316 1736 2513 1 Barrels of oil equivalent

2 Unrisked 3 The total reported is the sum of all probabilistic cases and will not equal the arithmetic sum of the individual zone or play type

due to the effects of statistical aggregation.

Summary — Page 3

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Table S-2b Summary of the Net1 Undiscovered In-Place Hydrocarbon Resources

PEP Block 38348 and Block 38349, New Zealand

BOE2-in-Place (MMbbls)3

Area Low Estimate Best Estimate High Estimate

PEP 38348 615 1002 1773

PEP 38349 601 710 866

Total 4 1316 1736 2513 1 Net Interest 100%

2 Barrels of oil equivalent 3 Unrisked 4 The total reported is the sum of all probabilistic cases and will not equal the arithmetic sum of the individual zone or play type


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. No fair market value has been assigned to these lands at this time. Out of the Company’s inventory of prospects and leads they have identified three non-contingent drilling locations which they plan to drill in 2009. The Company is currently negotiating a drilling contract with NRG Services to drill the initial two wells with an option to drill one additional well per permit. A total drilling budget of USD 3.3 million has been established and will be funded out of the Company’s current working capital. The drilling program will satisfy the work commitment requirements for each of the permits which require one well to be drilled on each permit prior to November 2009 to maintain the permits in good standing.

Summary — Page 4

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In Sproule’s opinion the estimated drill and complete cost of USD 1.1 million per well is reasonable given the estimated target depths. The company is continuing to evaluate new seismic data and plans to acquire additional seismic data over several of the target locations.

Discussion — Page 1

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Discussion General Overview Hydrocarbons are found in most New Zealand sedimentary basins (Figure 1). To date, all of New Zealand’s production has been from the Taranaki Basin, located in the southwest of the North Island. It is believed that the rest of the under-explored basins have potential for commercial hydrocarbon discoveries. Petroleum Exploration Permit (PEP) blocks 38348 and 38349 are situated in the East Coast Basin, on the North Island, as shown in Figure 2. The Government of New Zealand granted these exclusive permits on November 8, 2006. PEP 38348 covers a part of the basin north of Gisborne and PEP 38349 covers part of the Hawke Bay area and south to Cape Turnagain. The terms of both permits are identical with regard to the work program which must be carried out, as detailed later. The two blocks cover a large portion of the basin, with PEP 38348 extending over 530,524 acres and PEP 38349 extending over 1,633,331 acres. Figure 3 shows the location of the two blocks relative to other exploration permits and seismic data. Of the approximately 40 wells drilled in the basin (Figure 4), approximately 20 have been drilled in these two blocks. Although numerous gas and oil seeps have been documented, the East Coast Basin remains one of the least explored areas in New Zealand. Petroleum exploration in the basin started in the mid-1800’s, however, none of the wells drilled to date have encountered commercial petroleum accumulations. In general terms, the permit holder must, within 12 months of the commencement date of the permit, review the available seismic, reprocess and interpret as necessary, conduct geochemical studies, examine structures in prospective areas and carry out petrographic tests on reservoir and source formations. The permit holder must then make a commitment to complete the next phase of the exploration program, which requires, within 24 months of the commencement date of the permit, the acquisition, processing and interpretation of a minimum of 20 kilometers of 2D seismic data, additional geological, geochemical and geophysical studies and commitment to complete the third work program. The third phase requires the permit holder to drill one exploration well to an agreed objective or depth within 36 months of the commencement date of the permit. At the end of this period, the permit holder must surrender 25 percent of the permit area or surrender the entire permit. If a portion of the permit is retained, the permit holder must submit a work program proposal for the remainder of the permit term.


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With the Company’s current drilling program of three prospects, outlined in the table below, the Company will have fulfilled its work commitment for the first 36 months of the permits.

Drilling Prospects 2009

Prospect PEP Target Lithology Estimated Depth

Boar Hill 38349 Miocene turbidite Fractured Waipawa shale

1200 metres

Kowhai 38348 Upper-Mid Miocene Sandstone 1200 metres Waitangi 28248 Paleocene-Cretaceous Sandstone 750 metres

The East Coast Basin has been identified as having reservoir, source rock and trap potential. From the mid-1800’s, several petroleum exploration companies conducted exploration in the region. During this exploration phase, several companies, starting with BP, Shell and Todd in 1960’s, conducted seismic profiling of this vast basin. In addition, a number of oil and gas seeps, the majority being gas seeps, were identified by surface geological mapping all over the basin. The most significant of the oil seeps occur at Rotokautuku (north of PEP 38348), Totangi and Waitaning (within PEP 38348). Several exploratory wells drilled on the identified structures and encountered numerous minor oil and gas shows, however, the wells drilled in these two blocks did not yield commercial hydrocarbons. The lack of success has been attributed to the lack of an adequate understanding of the structural geology of the basin. Geological Review The East Coast Basin of New Zealand covers an area of approximately 75,000 sq. km or 18,532,500 acres, extending from East Cape, in the northeast, to Kaikoura, in the southwest. The region straddles the plate boundary where the Pacific Plate, to the east, is being subducted beneath the Australian Plate to the west. The basin is a complex structural province, bounded by the axial ranges in the west and the Hikurangi Trough in the east. From north to south, the region is sub-divided into three main geographic areas, the Raukumara Peninsula, Hawke’s Bay and Wairarapa. These areas are large and geologically complex. The basin fill is extremely thick, with more than 10,000 feet of sediments in some areas, and the stratigraphy is complex. A generalized stratigraphic column is shown in Figures 5 and 6. Figure 7 summarizes the petroleum systems of the East Coast Basin. It is suggested that some Late Cretaceous units, such as the Koranga, Te wara, Waimana, Wairata etc., are promising prospective reservoirs. Several Late Cretaceous to Paleogene units, such as the Tahora, Wanstead, Weber and Whangai formations, are also thought to have good reservoir potential.


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Finally, the Neogene Whangara, Wescott, Takirtini, Waipitaki, and Ngatapa formations, also have reservoir potential. In this analysis, 56 identified leads or prospects within the two blocks were considered; with the main target reservoir being Miocene sandstone and Pliocene limestone formations. Cretaceous formations were also considered as secondary targets, where appropriate. Prior to the issuance of the current permits, PEP 38348 was partially covered by PEP 38330, operated by Indo Pacific Energy Ltd. The previously identified leads and prospects on this block are shown in Figure 8. Figure 9 presents a map showing the leads and prospects identified within PEP 38348, the location of the 2D seismic control (blue), and the locations of the recorded oil (green) and gas seeps (red). Similarly, PEP 38349 was previously partially covered by PEP 38328 and PEP 38332, both operated by Indo Pacific Energy Ltd. The previously identified leads and prospects on those permits are shown in Figure 10. Figure 11 presents a map showing the leads and prospects identified within PEP 38349, the location of the 2D seismic control (blue), and the locations of the recorded oil (green) and gas seeps (red). Digital well log data for three exploration wells (Hukarere-1, Kereru-1 and Whakatu-1) was obtained from the New Zealand Ministry of Economic Development Crown Minerals website. These wells did not encounter any hydrocarbon-bearing formations when drilled. The well log data was primarily used to estimate the range of expected porosity values that would be used in the probabilistic model. This information was supplemented by porosity and permeability data measured on samples collected from outcrops within the permit area (Figure12). The assessment of the porosity ranges, listed in the table below, was also based on reports available on the New Zealand Ministry of Economic Development Crown Minerals website. Because the existing exploration wells within the two blocks did not encounter hydrocarbons, the range of water saturation values used in the model were based on water saturations found in other known hydrocarbon pools with similar porosity values. The range of prospective areas for the various leads was estimated from maps supplied by the Company or available from the New Zealand Ministry of Economic Development Crown Minerals website. The net reservoir thickness values used in the models was based on the target reservoir and ranged from 5 to 50 feet for sandstone reservoirs and 10 to 100 feet for several of the large carbonate reservoirs. The range of values used for the formation volume factor is considered reasonable to represent crude oils with a range of solution gas ratios.


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The following table lists the ranges of the various reservoir parameters used in the probabilistic analysis.

PEP Block 38348 and 38349 Range of Reservoir Parameters

Zone Pliocene Miocene Cretaceous

Reservoir Type

Limestone Sandstone /Carbonate Sandstone

Hydrocarbon Type

Oil/ Gas Oil/ Gas Oil/ Gas

Range Minimum Maximum Minimum Maximum Minimum Maximum

Porosity (%) 8 13 10 16 10 16

Water Saturation (%)

37 62 37 62 37 62

Net Reservoir Thickness (ft)

Varied by prospect/lead

Area (acres) A lognormal distribution based on the most-likely area defined by structural closure for each

prospect/lead was considered.

1/Bo (stb/rbbl) 0.8 0.9 0.8 0.9 0.8 0.9

These ranges are considered to be geologically reasonable. Source Rock Potential Mixed-marine late Paleocene and latest Cretaceous sediments are believed to be the main source rocks in the basin, as indicated by the chemistry of the oil and gas seeps. In the central part of the basin, the seeps and shows are dominated by gas with isotope ratios suggesting a mixed biogenic and thermogenic origin. The latter are thought to have originated from the deeply buried Cretaceous source rocks. In the Wairarapa area, the oil seeps have stable isotope signatures consistent with terrestrial source rocks but are, as yet, unmatched to any outcropping rock sequences; however, some Cretaceous marine units contain significant volumes of terrestrial organic material. From the available data, the Paleocene Waipawa Formation has good oil source rock potential, with some Cretaceous rocks exhibiting moderate potential. As mentioned previously, there is a chance that either oil or gas might be found in any given structure and, for the purposes of this report, oil has been assumed as the hydrocarbon fill.


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Reservoir Potential The following table summarizes the potential reservoir units in the East Coast Basin:

Potential Reservoir Units of the East Coast Basin, New Zealand.

Formation/ Unit Age RegionReservoir Potential

Thickness(m)

%Sand

Porosity %

PermeabilitymD

Limestone Plio-Pleistocene H, W Good ~100 - <11-50 0-43500 Silver Range L Miocene H, W Poor ~20 >90 8 <1

Hurupi L Miocene W Good 400+ 100 27 - Makaretu L Miocene R, H Good 50-100 70-90 5.6-26 2-174 Tunanui M Miocene R, H Good 200+ 70-90 11963 <5-207

Ngatapa Sst M Miocene H Medium ~150 100 - 10 Takiritini M Miocene W Good 15-1000 100 8.6-26 <1-218

Greenhollows M Miocene W Good 200+ >80 - 22 Whangara M Miocene R Medium ~200 >90 19-22 <4-80 Whakataki M Miocene W Medium 1000+ >50 17 15-25

Tahora Late Cretaceous R, H Medium 0-400 100 22 112 Glenburn Cretaceous R, H, W Poor 2500+ >90 39431 <1-20

Tapuwaeroa Cretaceous R Medium ~1000 >90 22 3-128 Regions: R= Raukumara Peninsula, H=Hawkes Bay, W=Wairarapa Outcrop studies have shown that the Miocene sandstones have generally better reservoir quality. Figure 12 shows the porosity and permeability relationship color-coded by age for PEP Block 38348, confirming that the upper Miocene sandstone formations have the best reservoir quality compared to the other formations. Seals Widespread reservoir seals of both lateral and stratigraphic nature are observed in the basin but their characteristics are not well documented. The smectitic Wanstead formation is considered to have better sealing characteristics for entrapment of hydrocarbons from Cretaceous and Paleocene sources. Similarly, mudstones act as seals to trap hydrocarbons in the Neogene sandstone and limestone formations.


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Traps The tectonic setting of the East Coast Basin, on both Cretaceous and Neogene plate boundaries, has resulted in a large number of widely distributed potential structural traps and a complex history of closure development and reactivation. While many structures are thrust-controlled, a strike-slip component cannot be ruled out. In addition, extensional faulting and rifting, especially during the late Cretaceous and Paleogene, have contributed to the creation of several sub-basins and prominent structures. The formation of several stratigraphic traps is also attributed to the interaction of tectonics and eustacy. The identified potential structural and stratigraphic traps in the two PEP blocks are individually described in the following section. Overview of Prospects and Leads in PEP 38348 and 38349 Methodology All available data was loaded into Schlumberger’s Petrel 3D visualization software to facilitate integration. This data included all 2D seismic lines, well locations, cultural features such as shorelines and lease boundaries, satellite imagery, including Landsat and digital elevation model (DEM) data, and an inventory of geo-rectified map images including surface geology and local and regional time structure maps. Prospect shapes, geochemical oil and gas seeps, and regional and local fault trends were captured from the inventory of maps as polygon elements within the Petrel project. The prospects polygons identified by the Company had been a combination of both seismic and surface topographic anomalies, however, the horizon interpretation was not provided and it was beyond the scope of this review to interpret the 2D data. The seismic was used within the visualization system for comparison against the Companies lead polygons. The information available for review by Sproule indicates that reservoir quality rocks are present within the two PEP blocks. Of the twenty wells drilled in the two blocks, digital well logs were available for only three wells (Whakatu-1, Hukarere-1, and Kereru-1). For the PEP 38348 block, fifteen prospects and leads, each with one or two prospective zones, were considered. Similarly, for the PEP 38349 block, forty-one prospects and leads were considered.


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The following tables list the prospects and leads considered for the PEP 38348 and 38349 blocks:

PEP 38348 Identified Prospects and Leads

Prospect/Lead Target Reservoir Lithology Hydrocarbon Pauariki Prospect Lower Miocene Sandstone Oil/Gas Matanui Lead Lower Miocene Sandstone Oil/Gas Mid-Waiau Lead Mid–Lower Miocene Sandstone Oil/Gas Mangaroa Lead Mid-Lower Miocene Sandstone Oil/Gas Kowhai Lead Upper-Mid Miocene Sandstone Oil/Gas Arataha Lead Upper–Mid Miocene Sandstone Oil/Gas Wharekaka Lead Upper–Mid Miocene Sandstone Oil/Gas Paroa Lead Upper–Mid Miocene Sandstone Oil/Gas Tolaga Deep Lead Mid–Lower Miocene Sandstone Oil/Gas Arakihi Anticline Lead Upper Miocene Sandstone Oil/Gas Kanakanaia Lead Lower Miocene Sandstone Oil/Gas Waingaromia Prospect Lower Miocene Sandstone Oil/Gas Waitangi Hill Crest Lead Paleocene-Cretaceous Sandstone Oil/Gas Te Hau Lead Lower Miocene Sandstone Oil/Gas Te Karaka Lead Lower Miocene Sandstone Oil/Gas


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PEP38349

Identified Prospects and Leads Prospect/Lead Target Reservoir Lithology Hydrocarbon

Port Napier Prospect Pliocene, Miocene and/or Cretaceous Limestone/Sandstone Oil/Gas

Palomino Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Fernhill Lead Pliocene Limestone Oil/Gas

Speedy Prospect Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Boar Hill Prospect Late Cretaceous Mudstone Oil/Gas

Seafield Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Maimai Lead Miocene Sandstone Oil/Gas

Runanga Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Carrick Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Clive Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Clifton Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Brookvale Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Cessna Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Burma Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Opapa Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Tukituki Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Kahahakuri Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Tikokino east Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Salisbury Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Gala Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Okauawa Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Ongonga East Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

El Dorado Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Parson Lead Pliocene Limestone Oil/Gas

Ashcott Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Rosearl Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Hatuma Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Woburn Lead Miocene Sandstone Oil/Gas

Awanui Lead Miocene Sandstone Oil/Gas

Tourere Lead Miocene and Eocene-Paleocene Sandstone Oil/Gas

Pukerua Lead Miocene Sandstone Oil/Gas

Maunga Lead Miocene and Eocene-Paleocene Sandstone Oil/Gas

Mangatoro Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Lakeview Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas


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PEP38349 Identified Prospects and Leads

Prospect/Lead Target Reservoir Lithology Hydrocarbon Oporae Lead Miocene Sandstone Oil/Gas

Waewaepa North Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Waewaepa South Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Waitahora Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Titree Lead Miocene and Oligocene Sandstone Oil/Gas

Mangaorapa Lead Miocene and Oligocene Sandstone Oil/Gas

Coonoor Lead Pliocene and/or Miocene Limestone/Sandstone Oil/Gas

Each of the anomalies is briefly described in the following discussion. PEP 38348 Pauariki Prospect This outcrop structure was formerly known as “Area 32” of Taranaki Oil Ltd, where the off-structure Waiapu-2 well was drilled in late 1927. Significant gas shows were reported during drilling of this well. The Pauariki structure consists of NNE-trending stacked hanging wall anticlines over low-angle WNW-dipping thrusts, with an observed minor south plunge on seismic and a north plunge from surface geology. The target reservoirs are the Lower Miocene sandstones and the Basal Miocene Whangara Formation. Lower Miocene shales act as seals. Possible source rock are the Paleocene–Maastrichtian marine carbonaceous shales (Waipawa Black Shale & Whangai Formation), and Upper Cretaceous carbonaceous shale interbeds. The deeper stacked anticlines are best imaged on 2D seismic line ip-330-97-01 and the closure appears weak on two lines (ip-330-98-101 & ip-330-98-101). Some gas seeps have been identified in the local area. Matanui Lead

This an outcrop structure referred to in 1928 by Taranaki Oil Ltd as being a potentially large feature with an axial surface mapped NNE-trending anticline. Surface exposure at crest is mid-Miocene mudstone. Reservoir targets include lower to basal Miocene turbidite sandstones. A single seismic line, ip3330-97-01, shows a large, but poorly imaged, shallow anticlinal high supporting the Company’s identified lead.


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Mid-Waiau Lead

One, or possibly two, anticlines were mapped by NZGS in 1991 in the middle reaches of the Waiau River, with axes immediately northwest of, and parallel to, the Waiau Fault Zone. Surface exposures are probably mid-Miocene. Reservoir targets are middle and lower Miocene sandstones. A gas seep was recorded on the Waiau Fault Zone 3 kilometers to the southwest, and the middle Miocene sandstones were reported to smell of oil. No seismic coverage was provided over this feature.

Mangaroa Lead This is a poorly imaged deeper structural complex that is only identified on 2D seismic line ip-330-98-101-2. Kowhai Lead This lead is not discernible from surface geology but was delineated using seismic. The structure is complicated and is terminated to the north by an east-west fault zone which has a diapiric and/or faulted core, bringing Eocene formations (including the Wanstead Formation) to surface adjacent to Upper or Mid-Miocene formations. Reservoir targets for this lead include Upper and Mid-Miocene turbidite sandstones, and possible fractured limestones lower in the Miocene. This lead is crossed by two orthogonal lines. While there may be some evidence for closure on the east-west 2D profile ip-330-98-102, the north-south profile ip-330-00-205 suggests there is a risk of leakage updip to the north. This structure is considered by the Company to be the second drilling candidate for 2009 following the drilling of the Boar Hill prospect of PEP 38349. The TD of the well is prognosed by the Company to be 1200 metres. The estimated drilling costs are USD 750,000 for a dry-hole with an additional USD 350,000 to complete the well if successful. The drilling costs for this well are to be funded out of the Company’s current working capital. The Company is negotiating for this well to be drilled by the NRG Services Drilling Rig #1. Arataha Lead


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This lead is a surface structure originally mapped by Taranaki Oil Ltd and subsequently listed as a closed structure by Vacuum Oil Co. It has a surface culmination in Upper Miocene mudstone, with a north plunge shown by surface dip on the uppermost Miocene Tokomaru Sandstone. Gas seeps and oil smells were observed in the Parehaka High 13 kilometers to the ENE of Arataha and in known source rocks across a major Pliocene depocentre and major fault. Although gas seeps have been recorded south of the Arataha Lead, recent isotope analysis shows these to be of shallow biogenic origin (swamp gas; Francis, 1998b). Reservoir targets are mainly Mid-Miocene turbidite sandstones. Although this lead is covered by three seismic profiles, the structure climbs steeply to the north (ip-330-98-104) and there appears to be a risk of leakage in that direction. Wharekaka and Paroa Leads There are hints of gentle rollover in surface geology 6–8 kilometers NNW of Tolaga Bay, around the northern margins of the wide Uawa River alluvial plains. These two leads are termed Wharekaka and Paroa. The Wharekaka Lead is associated with the NE-trending Marau Beach Fault (Strong 1927; Francis 1984). Surface exposures are of uppermost Miocene (Kapitean) sandstones and sandy limestone. However, the base Tokomaru Sandstone is usually unconformable on the underlying Mapiri Mudstone and surface dips are not necessarily indicative of deeper structure.

Gas was reported in water bores in the Uawa River plains, and flammable gas was encountered in two dynamite shot holes in the Tolaga Anticline to the south. There are numerous gas seeps and oil indications further to the north, south and west. Upper Miocene Hikuwai Sandstone, having good reservoir quality, is the primary reservoir target, with poorer quality, slightly older Kaiaua sandstone and the Mid-Miocene section as secondary targets.

The Wharekaka Lead is apparently bigger and has higher relief than does the Paroa Lead, although this comparison is based only on dip lines for Paroa. Wharekaka is more extensively covered by four dip lines and one strike line, while Paroa is partially covered by three dip lines. The seismic continuity is poor and the reflection energy is broken and discontinuous. Paroa may be more synclinal, while Wharekaka may have better developed closure on its SW flank. Tolaga Deep Lead This is a subsidiary footwall structure discernible immediately north of the faulted axis of the Tolaga Anticline, updip from the Kaiaua Syncline. Rollover is inferred to be in Mid-to-Lower


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Miocene and the structure is strongly unconformable below the inferred top Mid-Miocene. A small, stacked thrust in this area is supported by 2D seismic line ip-330-98-102. Arakihi Lead This structure is located on the eastern side of a major Pliocene depocentre (Waihora Syncline) as a surface anticline exposing top Miocene to Lower Pliocene. Seismic or well control is not available to delineate this structure. Reservoir targets include Upper and possibly Mid-Miocene sandstones. Surface geological observations (Francis, 1998a) suggest the anticline to be a hanging wall structure over a NW-dipping reverse fault. The structure is prognosed to be favorably situated with regard to mature source with a good drainage area. No 2D seismic coverage was available over this lead. Kanakanala Lead This structure is delineated from a surface anticline in the Waihora Valley, 8 kilometers southeast of the Waitangi seeps and 4 kilometers west of the Waihora Syncline, a major Pliocene depocentre. However, closure is uncertain, as it could not be confirmed from the available seismic data. Accordingly, the size of the closure is unknown. Two lines cross this lead (ip330-00-201 & -202) and, on both lines, this structure appears to be in a flank position and less prospective than some of the other leads. Waingaromia Prospect The most successful well in the East Coast Basin is the Waingaromia-1, drilled between 1884 and 1890. The well was situated near the axis of the Waingaromia Syncline but encountered oil and gas shows in several sandstone, limestone and conglomerate formations between 143 and 350 meters, and oil was apparently produced between 390 meters and the TD of 403 meters at a rate of 20 to 50 barrels per day. Recent exploration by Indo-Pacific Energy in the area lead to the drilling of the Waingaromia–2 well in May 2002, close to the Waingaromia–1 well and about 100 meters deeper. Although gas was present while drilling, the well was abandoned as dry. Gas collected at 493 meters contained 44% methane, 0.25% ethane, 117-ppm propane and 18-ppm butane. Most of the gas was believed to have come from fractures in concretions. Gas bubbles were observed in the core from 250 meters down. A strong gas kick at 348 meters, which was flared, came from a vuggy brecciated concretionary zone with open fractures. At 339 meters, oil was observed from an open fault dipping at 40°, which had strike-slip displacement.


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In summary, the Waingaromia-2 well, drilled to test the potential hydrocarbon-bearing formations encountered in the Waingaromia-1 well, did not encounter any of the anticipated Mid- and Lower Miocene sandstone formations (Waingaromia-2 Well Completion Report). The 2D seismic line ip330-00-301 shows the possibility of a fault-dependent trap against a major fault in the vicinity of this lead. Waitangi Hill Crest Lead The Waitangi seep area was the target of exploration in the early 1900’s. After drilling five shallow wells, Gisborne Oil Company drilled two deeper wells towards the centre of Waitangi hill and about 600 meters north of the main seeps. The area was interpreted to be a fold-dominant structure. Gas and oil shows were encountered in several horizons in the Waitangi-1 well, with the most significant shows recorded from a greensand associated with “brown shales” at about 200 meters. The greensand could be associated with the Rakauroa Member of the Whangai Formation or, alternatively, with Waipawa Black Shale or Wanstead Formation. Surface exposure is very patchy but these formations are present in the Waitangi Crest area. In 1912, the oil-bearing greensand zone at 200 meters was perforated and produced about 10 bbl/day of oil. The casing of Waitangi-1 still bubbles gas and oil. No 2D seismic coverage was provided over this lead but nearby line ip330-00-301 shows a major fault immediately to the south and the structure appears to be rising towards this lead at the end of this line. This structure is considered to be the third drilling candidate by the Company in 2009. It is proposed to be drilled following the Boar Hill prospect (PEP 38349) and the Kowhai prospect (PEP 38348) to a total depth (TD) of approximately 750 metres. The Company may acquire some additional seismic following a review of the first two wells, before spudding a well into this structure. The estimated drilling cost for this well is USD 750,000 for the dry-hole case with an additional USD 350,000 to complete the well in the event of a success. The drilling costs for the well, are to be funded out of the Company’s current working capital. The Company is negotiating for this well to be drilled by the NRG Services Drilling Rig #1. Te Hau Lead Te Hau is a minor rollover structure situated immediately southwest of the Waitangi High and seven kilometers from the main oil seeps. South-dipping Lower Miocene sandstone can be seen in surface outcrops and the fault (or unconformity?) juxtaposing the complex high is only one kilometer to the north. Lower Miocene sandstones and discontinuous limestones occur close to


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this contact. The prospect is small, extending about 700 meters along the rollover, but could represent an interesting flank prospect to the exposed oil-rich Waitangi High, if closure to both north and south could be established. No 2D seismic coverage was provided over this lead but nearby line ip330-00-204 shows that the structure appears to be rising towards this lead at the end of this line. Te Karaka Lead This is a structural high with NW-dipping Mid- to Lower Miocene and SE-dipping Lower Pliocene formations close to the Totangi oil seeps. One shallow well was drilled to a depth of 150 meters by O.A. Browne Company in 1957 but no data is available on the well. Surface exposures are concealed by extensive Upper Quaternary alluvium and Lower Quaternary lakebeds. No seismic coverage was provided for this lead. PEP 38349 PEP 38349 largely consists of approximately 7 to 10 kilometres of prospective Mid-Cretaceous to Quaternary section. Black and grey shales of Upper Cretaceous–Paleocene age are the main marine source rocks. Miocene–Quaternary reservoirs and seals are inferred to be present in the area, with indications of late burial, hydrocarbon maturation and migration. Several oil seeps to the south of the permit are linked to thermogenic and biogenic source rocks. The predominant structural element is the Miocene to Late Pliocene and Quaternary basin development in a compressive-wrench regime. The main reservoir targets are the Upper and Mid-Miocene turbidites, shelf sandstones and fractured limestones, Pliocene coquina limestones with possible turbidites, and possible Upper Cretaceous–Paleocene sandstones and fractured shales. Port Napier Prospect This rollover and SW-plunging structure indicates a Late Pliocene high from surface geology. The well Hukarere-1 was drilled on the structure in late 2001 and was abandoned as dry. The well was drilled to a total depth of 10,598 feet to test the hydrocarbon potential of the Pania Anticline. The well was drilled on reclaimed land in the Port of Napier. At 4,250 feet, the Mangatoro Formation was encountered, resting conformably on the Haupori Sandstone. The top of the Wanstead Formation was encountered at 6980 feet. The Whangai Formation was encountered at 9,068 feet, with an unusual facies of intensively calcite-veined mudstone at


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9,220-9,522 feet, interpreted as a fault zone. The Glenburn Formation was penetrated at 10,127 feet and encountered gas up to 23%. A perforation test of the interval between 10,431 and 10,513 feet flowed only water. A second test through perforations at 10,352-10,364 feet did not show significant pressure buildup and 22 barrels of water were swabbed to surface. Petrophysical analysis of the Hukurere-1 well showed that the Haupori, Waitere and Glenburn formations have better hydrocarbon potential compared to the remainder of the logged section. The Haupori sandstone, with a gross vertical thickness of 597 feet, did not have any gas shows while drilling. The Waitere Formation that covers the Late Miocene succession between the Mokonui and Waitere unconformities, comprises a fining-upward sequence that grades from sandstone to siltstone. In the first four feet of the formation, samples exhibited a weak pale greenish-blue crushed cut and bluish-white residual ring but without any direct fluorescence. A few other samples showed slow blooming milky white cut without any fluorescence. Minor background gas was observed while drilling the section. Petrophysical analysis showed the formation to have a gross vertical thickness of 1223 feet. Several thin sections from the Glenburn sandstone show poor porosity with high clay content. The interval 10,400-10,500 feet MD had porosity of 15% and a calculated water saturation in the range of 75-85%. The 2D line ip328-99-201 clearly shows a prospective anticlinal closure supporting this prospect. Palomino Lead This structure is situated to the east of Whakatu-1 and is seismically defined by a separate rollover. The primary reservoir targets are Pliocene limestone and Miocene sandstone units. Sproule’s petrophysical interpretation of the Whakatu-1 well shows that the entire logged interval is devoid of any hydrocarbon potential, except for the Waipuna limestone section that shows an average porosity of 8% and an average water saturation of 50%. This zone, with an estimated 32 feet of low-porosity net pay, is the most promising section in the well. The geological summary from the well completion report identifies the interval as calcareous sandstone grading to sandy limestone. Gas levels were relatively low, with C1 values of 85-285 ppm; however, the C2 levels were very high, ranging up to 35 ppm. No C3 or heavier components were present. According to the well completion report, the anticipated Pliocene and Miocene reservoirs were absent in the vicinity of the Whakatu structure. The 2D line g328-98-117 shows that the deeper structure rises from quite steep flanks and flattens out on the crest of the deep structure, and may have a rollover closure component. The shallower section does not appear to have closure. Fernhill Lead


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This structure lies inland to the west of the Hawke’s Bay area and is poorly defined on the existing seismic lines. The Mangapanian-Nukumaruan regressive phase in this area is dominated by carbonate lithofacies within the Te Aute sediments, which are common throughout the Hawke’s Bay area. The prospective primary reservoir target is the Mangapanian (Late Pliocene) limestone. Good quality seismic on lines such as 97-02 show a fault-dependent high-side closure against a major fault at depth that develops a significant rollover in the shallow section. Speedy Prospect The Speedy prospect is located in the central part of the East Coast Basin, close to known Cretaceous-Paleocene source rocks, Mid-to Late Miocene turbidite sandstones, Early and Mid-Pliocene coquina limestone reservoirs, and Miocene-Pliocene seals. The structure is a northeast trending seismically defined 4-way dip closure. Hydrocarbons are inferred to have migrated from a substantial half-graben some 5 kilometers to the northwest of this structure. One well, Speedy-1, drilled in mid-2000 to a total depth of 876 meters, was plugged and abandoned as dry. The well failed to reach the target horizon due to mechanical difficulties during drilling. The stratigraphic succession encountered by the well consisted of Upper Miocene claystone formation with minor sandstones, unconfirmably overlain by Mid-Pliocene claystone and sandstone formations. A maximum mud gas level of 2.71% was recorded at 430 meters. The Tukituki (Mangapanian) sandstone, Te Onepu limestone formations overlie the claystone formation. Inferred porosity and permeability in this section are good to very good. The Te Onepu limestones are part of the Te Aute Limestone group in the Hawke’s Bay area. Finally, the Quaternary mudstones, oyster beds and gravel beds were encountered to the surface. Boar Hill Prospect This is a reasonably well-defined seismic structure confirming the surface geological mapping. The structure is defined by two dip seismic profiles (ip332-98-207 and ip332-99-3030 and one strike seismic profile (ip332-99-302). Although there is evidence of a great deal of faulting, all three of these 2D seismic profiles exhibit a general antiformal shape. This structure is considered as the first drilling candidate by the Company in the second quarter of 2009 to a TD of approximately 1200 metres. It is inferred that stacked thrusts of Whangai Formation and older in core of structure can be encountered. Reservoir targets prognosed by the Company include both the Miocene-aged turbidite sands and potentially, the Waipawa and Whangai oil


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shales. Three 2D seismic profiles show a major subsurface structure supporting this prospect. A major regional fault on the north and east flanks dramatically terminates the structure. The Company has 50 km of newly acquired 2D seismic data which was not available at the time of the Sproule review which has increased their confidence in the closure. The Company is negotiating for this well to be drilled by the NRG Services Drilling Rig #1. The drilling costs for the well are to be funded out of current working capita. The estimated drilling cost for a dry-hole are USD 750,000 in the case of a dry-hole with an additional USD 350,000 to complete the well. Seafield Lead The Seafield lead is a rollover structure situated northwest of Napier. A 3-way closure is defined by seismic interpretation of Indo Pacific 1998 lines, with no closure definition to the northwest. Late Miocene to Pliocene formations are the prospective reservoirs. Maimai Lead This is a poorly defined sub-unconformity rollover structure flanking the Port Napier prospect, with Miocene formations as probable reservoir targets. The rollover feature shows an attractive amplitude anomaly at the crest of the closure on 2D seismic profile ip328-99-202, supporting this lead. Runanga Lead A small rollover is seen on dip line 89C-01 but is not adequately defined to the north or south due to a lack of strike line control. Similar to the Fernhill lead, the primary reservoir target is considered to be the Mangapanian (Late Pliocene) limestone.


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Carrick Lead This structure was identified on several seismic lines. Gas bubbles were reported from a shallow water well drilled near the structure. Similar to the Fernhill lead, the primary prospective reservoir target is expected to be the Mangapanian (Late Pliocene) limestone. Carrick appears to be a more subtle closure, as shown on offsetting line 97-04. Clive Lead Seismic lines 98-114-97-01 and g328-98-105 show this feature to be a high-side, likely fault-dependent closure against a major down-to-basement fault. Similar to the Carrick structure, gas was reported from a water well drilled on the northwestern flank of the structure. The primary reservoir targets are Pliocene limestone and Miocene sandstone units. Clifton Lead Situated at the northern end of the extensive Elsthorpe Anticline on the coast, this structure is identified on seismic lines 98-114-97-01 and just off g328-98-105; however, definition of the northern and southern closures is not clear. Possible reservoir targets are the Pliocene limestone, with secondary objectives in the Miocene sandstone units. There appears to be high-side hanging wall rollover closure (particularly at shallower depths) against a major down-to-basin fault. Brookvale Lead A minor rollover is seen on seismic line L98-115 at the end of the line. It is also seen as a high on the southern end of lines 99-205 and 301, with possible definition on line L204. This structure is located to the north of Havelock North town. Reservoir targets could be the Pliocene limestones, with secondary targets in the Miocene sandstones. While 2D seismic line ip328-99-301 rises towards this anomaly, the structure lacks direct seismic control. Cessna Lead This structure is characterized by a distinct surface topography feature defined by mid-Pliocene limestone. The structure is seen as an asymmetric hanging wall rollover on a NW-dipping


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reverse fault on the available seismic lines. Shallow lower Pliocene limestones and deeper Upper to Mid-Miocene turbidites are the main reservoir targets. No 2D seismic was available over this lead. Burma Lead This structure is identified from surface geology as a 3-way rollover expressed in mid-Pliocene limestones. The Pliocene limestones and Late Miocene sandstones are the possible reservoir targets. No 2D seismic was available over this lead. Opapa Lead Surface geology indicates a 4-way closure in mid-Pliocene limestones with targets from shallow Lower Pliocene limestones and, possibly, Upper and Mid-Miocene turbidites and Paleocene sandstones. No 2D seismic was available over this lead. Tukituki Lead This is a surface structure to the west of the Patangata Syncline, with gentle dips in Pliocene limestones that define rollover and a northerly plunge. No 2D seismic was available over this lead. Kahahakuri Lead This is likely a steeply dipping fault-dependent closure as best illustrated on 2D line “th”. The steepness hinders the liklelihood of trapping large volumes. Tikokino East Lead This is a steeply dipping deep fault-bounded trap discernible on line g328-98-109. It is not clear if there is roll-over on this deep structure as the seismic character appears to be strongly influenced by diffractions extending off the crest of the structure.


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Salisbury Lead This is a small rollover on seismic line C91-04, mainly below the unconformity. It increases in size, and closes higher to the south, on line C91-05. The structure may be en-echelon to the Kereru structure, which is a 4-way dip closure. The area of closure at the mid-Mangapanian level is approximately 8 square kilometers. Kereru-1 was drilled almost on the crest of the upper gently folded sequence, and about 900 meters west of the crest of the unconformity. There were no visual hydrocarbon shows in either cuttings or sidewall cores. Several recorded gas shows were mostly background and predominantly methane. The highest gas values were recorded in the Tirowhenua mudstone at 3,785 feet and between 4,000 and 4,100 feet. This well was plugged and abandoned as dry. In the Ohara mudstone interval, porosity values of 16% and water saturation values up to 40% were computed in several zones; however, the results are suspect due to poor hole conditions. In the zone of highest total gas readings within the Tirowhenua mudstone, log analysis does not indicate any hydrocarbon saturations. In Salisbury, the reservoir targets are the Pliocene limestones and Miocene sandstones, as in the Kereru structure. No 2D seismic was available over this lead. Gala Lead This is a broad, shallow rollover trending NNE–SSW on seismic data. It is interpreted that this lead could be contiguous with the Okauawa lead. It is inferred that Upper Miocene sandstones are present below the Pliocene. This is an attractive feature with good areal extent that appears to have some associated amplitude anomaly, for example, on 2D line ‘tb”. Okauawa Lead This structural high is seen at the east end of seismic line C91-05, with a slight rise on line 89C-02, and evidence of structure on surface geology. Reservoir targets are the formations above and below the mid-Pliocene unconformity. The 2D seismic (eg. line “tc”) is extremely poor over this lead and does not compare favourably against other opportunities. Ongonga East Lead The Ongonga East structure lies south-east of the high drilled by the Ongonga-1 well. According to the well completion report, Ongonaga-1 was drilled on a closed subsurface seismic high to


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test the hydrocarbon potential of the Pliocene carbonate that exhibits good porosity and permeability in outcrop. The well was drilled to a total depth of 5,162 feet, with no significant hydrocarbon indications. The Ongonga East structure is a separate down-dip fault block, having the same objective of Pliocene limestone targets. This fault block may exhibit some fault-independent rollover closure but additional seismic is required for validation. El Dorado Lead The structure is characterized by a gentle rollover at the intersection of two seismic lines passing through the crest. Closure to the south is not well defined. The primary reservoir target is the Mid-Pliocene coquina limestone, with a possible Pliocene and/or Miocene sandstone target. The 2D seismic profile “tp” illustrates and supports this anticlinal carbonate build-up with relatively clean seismic continuity. Parson Lead This lead is an unusual mound interpreted on seismic line 97-11, inferred by the Company to be a Pliocene coquina limestone body. However, it may just be a steeply dipping fault-dependent lead. Closure is not confirmed due to a lack of adequate strike lines. The structure may possibly be connected to the Speedy lead to the south and a poorly imaged mound to the north. The reservoir target is shallow and assumed to be close to outcrop. Ashcott Lead Ashcott is delineated as a rollover near the north end of seismic line 97-05 (near-strike), with a suggestion of dip rollover at the extreme eastern end of the line. Surface geology indicates that the Pliocene limestone flattens out, suggesting that the rollover is in the Miocene section. Rosearl Lead This structure is identified on a single dip line as a rollover and a strike line is required to confirm closure. Mid-Pliocene coquina limestone is the primary reservoir target, with a possible secondary objective in the deeper Miocene sandstones. A rollover feature seen on line 97-05, which could be a possible carbonate buildup, provides some support for this interpretation.


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Hatuma Lead This is a moderately large rollover seen on seismic line 97-05 (near-strike) below the unconformity. The seismic quality is very good on this line and the structure appears to have substantial relief. Western regional dip is evident from other seismic lines. More seismic lines through the crest would better define closure to the east. The primary reservoir targets would most probably be the Mid-Pliocene coquina limestone and, possibly, deeper Miocene sandstones. Woburn Lead This is a structural high between the Hatuma and Awanui leads. It is well defined on two reprocessed seismic lines, 97-05 and 98-204. It is a robust Miocene structure underlying a Pliocene syncline. The top of the Miocene section was eroded during the early Pliocene. Awanui Lead This is a double rollover structure near the western end of lines 97-05, 332-98-204 (dip) and 332-98-205 (strike). The structure is situated close to the Waewaepa–Oruawharo fault. It is inferred that the closure is probably of Miocene age. Tourere Lead This is a surface anticline with visible Upper Miocene outcrop exposure. The structure is parallel to the Pukerua lead and is located 2.5 kilometers east of it. The reservoir targets are Lower Miocene and possible Eocene-Paleocene formations. No 2D seismic was available over this lead. Pukerua Lead Pukerua is delineated as a small surface anticline in the Pliocene, located 500 meters east of the Oruawharo fault. The east side syncline appears to show favorable plunge reversal. The primary reservoir targets are the Upper and Lower Miocene sandstones. No 2D seismic was available over this lead.


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Maunga Lead This is a surface anticline, faulted against the Pliocene section to the east, and located near the Oruawharo fault. Oil indications were reported in surface exposure of sandstones at the crest. Reservoir targets include Lower Miocene and, possibly, Eocene-Paleocene formations. No 2D seismic was available over this lead. Mangatoro Lead This structure is an inferred high, immediately east of the Waewaepa fault, comparable to the Waewaepa leads. One seismic line was shot (98-206) but the data is very poor. Possible targets include lower Pliocene limestone and Upper and Lower Miocene sandstones. This lead is crossed by one 2D profile, 98-206, and appears to be in a flank position and less attractive than many other leads. Lakeview Lead This structure is barely discernable as a hanging wall rollover on reprocessed seismic line 332-98-206, toward the southeast end, and situated 4 kilometers SE of the Waewaepa–Oruawharo fault. It is considered to be a relatively shallow prospect, with probable Miocene formations under the base-Pliocene unconformity. This lead is crossed by one 2D profile, 98-206, and appears to be an attractive high-side fault-dependent closure that may have a rollover component. Oporae Lead This is a surface 4-way closure defined on the west by the mid-Pliocene limestone and, on the east, by dip on the Upper Miocene. High local topographic relief is reported on the structure. Possible reservoir target formations are the Upper Miocene sandstones at or near the unconformity, with a secondary objective in Lower Miocene sandstones preserved between the Paleocene and Upper Miocene. No 2D seismic was available over this lead.


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Waewaepa North and South Leads Waewaepa-North is a 4-way surface closure defined in mid-Pliocene (Mangapanian) limestone. Possible targets include lower Pliocene limestones, and Upper and, possibly, Lower Miocene sandstones. It is characterized by a long northerly plunge, separated by a gentle saddle from the Waewaepa South lead. Subsurface closure is not confirmed due to lack of adequate seismic definition. The Waewaepa and Coonoor leads are to the east of Waewaepa fault. Oil and gas seeps are observed in breached anticlines to the east of these leads. The Waewaepa South lead has a long southerly plunge. No 2D seismic was available over these leads. Waitahora Lead This lead is situated along the same trend as, and to the north of, the Waewaepa leads but has a poorer surface signature. The potential reservoir targets are Lower Pliocene limestones, Upper and, possibly, Lower Miocene sandstones. No 2D seismic was available over this lead. Titree Lead This is a surface anticline with mid-Miocene outcrop exposures. Reservoir targets are possibly Lower Miocene turbidites and top Oligocene sandstones. The Wescott oil seeps lie to the west of this lead. No 2D seismic was available over this lead. Mangaorapa Lead The Mangaorapa Anticline lies across the Akitio Syncline axis from Boar Hill. Reservoir targets are similar to the Titree North lead. No 2D seismic was available over this lead. Coonoor Lead This is an outcrop high to the SSW of the Waewaepa South lead. Reservoir targets are similar to the Waewaepa leads. No 2D seismic was available over this lead.


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Summary of the Resource Assessment of the identified Prospects and Leads Based on our review of the information made available to us, it is apparent that:

• reservoir quality rocks are present within the two PEP blocks, • source rocks have generated hydrocarbons in the basin and there has been migration

through the system, and • prospective structures are present on the blocks.

However, it is also apparent that:

• most of the identified structures are poorly defined at this time and additional data may invalidate them,

• there is insufficient stratigraphic data to provide confident identification of prospective reservoirs within the identified structures,

• there is insufficient data to determine whether trap formation pre-dates hydrocarbon migration,

• original charged traps may not have been preserved in this active basin, • the basin is both oil- and gas-prone but small gas pools would not be economic to

produce and it would have to be determined if even large volumes of gas, if discovered, would be economic.

Based on this review, it is our opinion that the current risks and uncertainties applicable to these blocks are numerous and suggest that the geological risks are high. Also, at this immature stage of basin development, we have treated the prospects as if they were independent, however, this is not so. As additional seismic is shot and wells are drilled, the probabilities associated with the remaining undrilled prospects will change in accordance with the accumulated well results. In our assessment, we have acknowledge geological risk and inter-dependence of the prospects by incorporating a P99 net pay value of zero for each prospect or lead in our analysis. It is our opinion that the basin is too immature to justify estimation of recoverable hydrocarbons, thus we have limited our assessment to the estimation of undiscovered in-place resources. In assessing the undiscovered resources for these PEP blocks, ranges of reservoir parameter values for porosity, water saturation, area, net pay and shrinkage factors were estimated for each prospect or lead, and incorporated into a probabilistic software model, using either triangular or lognormal distributions. The lognormal distributions were modeled using assumed P10 and P90 end points. The model was run for 10,000 iterations, from which a distribution of all possible outcomes was created. The totals for each prospect or lead were summed statistically in order to estimate an aggregated expected outcome. Note that the arithmetic sum


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of individual volumes for each prospect or lead will not equal the statistical sum due to aggregation effects. Based on the probabilistic model built for PEP Blocks 38348 and 38349, low, best and high estimates for the undiscovered in-place oil resources were selected, using the P90, P50 and P10 values from the output distribution. These results are presented in Table 1a for the gross volumes and Table 1b for the net volumes. These volumes are reported as unrisked volumes; specifically, Sproule has not applied any geological risk factors or economic criteria to these estimates. Note that 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 PEP Blocks 38348 and 38349, East Coast, New Zealand

Probabilistic Estimate of Gross Undiscovered In-Place Hydrocarbon Resources

Low Estimate Best Estimate High Estimate

Area Gross BOE1-in-Place (MMbbls)2

PEP Block 38348 615 1002 1773

PEP Block 38349 601 710 866

Total 3 1316 1736 2513 1 Barrels of oil equivalent

2 Unrisked 3 The total reported is the sum of all probabilistic cases and will not equal the arithmetic sum of the individual zone or play type



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Table 1b

PEP Blocks 38348 and 38349, East Coast, New Zealand Probabilistic Estimate of Net1 Undiscovered In-Place Oil Resources2

Low Estimate Best Estimate High Estimate

Area Gross BOE3-in-Place (MMbbls)

PEP Block 38348 615 1002 1773

PEP Block 38349 601 710 866

Total 4 1316 1736 2513 1 Company Net WI 100 percent 2. Unrisked

3. Barrels of oil equivalent 4. The total reported is the sum of all probabilistic cases and will not equal the arithmetic sum of the individual zone or play type

due to the effects of statistical aggregation. Shale Gas Potential In addition to conventional opportunities, the Company is also pursuing an unconventional fractured shale gas play in the Waipawa-Whangai formations, which also serve as a source rock within the area. Based on this, an application has been filed for an additional license immediately south of PEP 38349 (Figure2). A study of the shale gas potential of the Waipawa and Whangai formations by GNS Science of New Zealand indicated that the Whangai can be quite thick, with low to moderate richness and maturity, while the Waipawa appears richer but of more modest thickness (Figures 13 and 14). Subsurface data for this play is sparse but the Company plans to collect additional outcrop data. These rocks vary in burial depth from surface to in excess of 10,000 feet. If sufficiently fractured, these source rocks could also have reservoir potential. GNS Science also compared the thickness, richness, and maturity characteristics of the Waipawa and Whangai fractured shale source to analogue formations in North America such as the Bakken play in Montana and Barnett shales in East Texas. While Sproule recognizes that potential may exist in this unconventional play, no data is available to permit an assessment of its resources to be made at this time. Minimum information required in order to confirm this potential includes such data as gas analyses, desorption isotherm tests, gas recovery from preserved cores and drilling mud gas shows. Ultimately, well


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test and/or production data and economic analysis will be required in order to identify and estimate reserves for the play. Minimum Work Obligations The PEPs granted to the Company by Crown Minerals, New Zealand, stipulate the length of time for the Exploration Period, which, for these permits, is 60 months. As the terms for both permits are essentially the same, the information set out below applies to both PEP 38348 and 38349 blocks, except where noted. The work program for both the permits is

a) Within the first 12 months: i. Review available seismic data and reprocess and interpret as necessary; ii. Conduct geochemical surveys over identified prospects/leads. Review the results

of this work and prioritize prospective areas and prospects/leads; iii. Examine structural and stratigraphic relationships of prospective areas and carry

out petrographic analysis including porosity and permeability tests of reservoir and source formations.

And make a firm commitment to complete the following: b) Within 24 months of the commencement date of the permit:

i. Acquire, process and interpret a minimum of 20 km of 2D seismic data on PEP 38348 and 30 km of 2D seismic data on PEP 38349;

ii. Undertake additional geological and geochemical studies and appropriate geophysical studies, including detailed interpretation of existing and the reprocessed and newly acquired seismic data described above.;

And make a firm commitment to complete the following: c) Within 36 months of the commencement date of the permit:

Drill one exploration well to an agreed objective and/ or depth unless geological or engineering constraints encountered whilst drilling make this unreasonable;

And submit by notice in writing a work program for the remainder of the permit term and surrender 25% of the permit area or surrender the permit.

The royalty rate for the produced crude oil is set as a sliding scale with reasonable rates. There is no minimum expenditure on either PEP. The work obligation set out in both agreements is considered to be reasonable and achievable by the Company, given the 5-year exploration period.


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Work Plans and Budget The Company is negotiating for their first wells to be drilled by the NRG Services Drilling Rig #1 commencing the second quarter of 2009. The first three wells currently planned will target the Boar Hill prospect of PEP 38349 and the non-contingent Kowhai and Waitangi prospects of PEP 38348. Costs for these wells, to be funded out of current working capital, are estimated at USD 750,000 each for a dryhole case and USD 350,000 additional to complete each well in the success case for a total budget of USD 3.3 million. In Sproule’s opinion the work program being followed by the Company is following the work commitment requirements listed as part of the terms and conditions of the PEP Permits. Each of the drilling targets are stand alone prospects.

Appendix A — Page 1

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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.


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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.


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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.


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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

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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


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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


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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


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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 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

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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.


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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


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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.


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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.

References

1. Crown Minerals web site information 2. Dave Francis, Dave Bennett, Steven Courteney, ”Advances in understanding of onshore

east coast basin structure, stratigraphic thickness and hydrocarbon generation”, 2004 New Zealand Petroleum conference proceedings.

3. Ozolins, V., and Dave Francis, “Whakatu-1 well completion report”, Petroleum Report Series PR 2476, Crown Minerals Website.

4. Westech Energy New Zealand Ltd., “Hukarere-1 well completion report”, Petroleum Report Series PR 2656, Crown Minerals Website.

5. Johnston, J.G., and D. A. Francis., “Kereru-1 well completion report”, Petroleum Report Series PR 2283, Crown Minerals Website.

6. Field, B.D., Uruski, C.I., et al.: “Cretaceous-Cenozoic geology and petroleum systems of the East Coast region, New Zealand”, Geological monograph 19, Institute of Geological and Nuclear Sciences Ltd., New Zealand.

7. Indo-Pacific Energy (NZ) Ltd., “Waingaromia-2 well completion report”, 2002, Petroleum Report Series PR 2767, Crown Minerals Website.

8. Indo-Pacific Energy (NZ) Ltd., “Speedy1/1A well completion report”, 2000, Petroleum Report Series PR 2537, Crown Minerals Website.

9. Beaver Exploration (NZ) Ltd., “Ongonga-1 well completion report”, 1971, Petroleum Report Series PR 271, Crown Minerals Website.


3738.70483.DJC.db


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


3738.70483.DJC.db


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.


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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.

References

1. Crown Minerals web site information 2. Dave Francis, Dave Bennett, Steven Courteney, ”Advances in understanding of onshore

east coast basin structure, stratigraphic thickness and hydrocarbon generation”, 2004 New Zealand Petroleum conference proceedings.

3. Ozolins, V., and Dave Francis, “Whakatu-1 well completion report”, Petroleum Report Series PR 2476, Crown Minerals Website.

4. Westech Energy New Zealand Ltd., “Hukarere-1 well completion report”, Petroleum Report Series PR 2656, Crown Minerals Website.

5. Johnston, J.G., and D. A. Francis., “Kereru-1 well completion report”, Petroleum Report Series PR 2283, Crown Minerals Website.

6. Field, B.D., Uruski, C.I., et al.: “Cretaceous-Cenozoic geology and petroleum systems of the East Coast region, New Zealand”, Geological monograph 19, Institute of Geological and Nuclear Sciences Ltd., New Zealand.

7. Indo-Pacific Energy (NZ) Ltd., “Waingaromia-2 well completion report”, 2002, Petroleum Report Series PR 2767, Crown Minerals Website.

8. Indo-Pacific Energy (NZ) Ltd., “Speedy1/1A well completion report”, 2000, Petroleum Report Series PR 2537, Crown Minerals Website.

9. Beaver Exploration (NZ) Ltd., “Ongonga-1 well completion report”, 1971, Petroleum Report Series PR 271, Crown Minerals Website.

Figure

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1

Highlighting Major Onshore and Offshore Basins with 2D, 3D seismic and wells.

Map of New Zealand

East Coast Basin

Source: New Zealand Ministry of Economic Development Crown Minerals

Taranaki Basin

Figure

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2

Highlighting PEP 38348 and PEP 38349

Map of East Coast Basin New Zealand

East Coast Basin

Figure

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3

Highlighting PEP 38348 and 38349.

Map of East Coast Basin

Source: New Zealand Ministry of Economic Development Crown Minerals

Figure

70483

4

Well Location Map

North Island, East Coast Basin

Source:GeoSphere

Figure

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5

Generalized Stratigraphy of the East Coast Basin New Zealand

Figure

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6

Generalized Stratigraphy of the East Coast of New Zealand (After Dave Francis et. Al.,)

Figure

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7

Summary of Petroleum systems of the East Coast of New Zealand (After Dave Francis et. Al.,)

Figure

70483

8

Leads and Prospects identified on previous permit PEP38330

0 4 8km

Figure

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9

PEP 38348 - Leads with 2D Seismic Control and location of oil and gas seeps

Gas Seep

Oil Seep

0 4 8km

Figure

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10

Leads and Prospects identified on previous permit PEP38330

0 5 10km

Figure

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11

PEP 38349 - Leads with 2D Seismic Control and location of oil and gas seeps

Gas Seep

Oil Seep

0 5 10km

Figure

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12

0 10 20 30 40

10

1

0.1

0.01

100

1000

Porosity (%)

Perm

eabi

lity

(mD

)

Upper Miocene Middle Miocene Lower Miocene

Top CretaceousUpper Cretaceous + Mid-Cretaceous

Basal Miocene

Porosity Permeability cross plot for some select outcrop samplesfrom the PEP Block 38348. (Adapted from Ref.2 Dave Francis et. al)

Figure

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13

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Figure

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14

Com

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Wha

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Nor

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technical assessment of the undiscovered …

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