tag sproulereport 12-31-08

8/9/2019 TAG SprouleReport 12-31-08

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Copies: TAG Oil Limited (5 copies)

Sproule International Limited (1 copy)

Electronic (1 copy)

Project No.: 3219.70535

Prepared For: Austral Pacific Energy Limited.

Authors: Sunday O. Edobor, P. Eng.

Douglas J. Carsted, P. Geol.Donald W. Wood, P. Eng

Exclusivity: This report has been prepared for the exclusive use of TAG Oil Limited., and

shall not be reproduced, distributed, or made available to any othercompany 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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Table of Contents Page 1

Table of Contents

Introduction

Field Operations

Historical Data, Interests and Burdens

Evaluation Standards

Evaluation Procedures

Evaluation Results

BOE Cautionary Statement

Forward-Looking Statements

Exclusivity

Certification

Permit to Practice

Certificates

Summary

Table S-1 Summary of the Evaluation of the P&NG Reserves

of Tag Oil Ltd. in the Cheal Area of New Zealand

(As of December 31, 2008),Before Income Tax

Table S-2 Summary of Selected Price Forecasts

(Effective December 31, 2008)

Table S-3 Summary of Reserves and Net Present Values

Total Proved Plus Probable Plus Possible ReservesBefore Income Tax

Table S-3A Summary of Reserves and Net Present Values

Total Proved Plus Probable Reserves

Before Income Tax


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Table of Contents Page 2

Figure S-1 Map of New Zealand Highlighting

Petroleum Exploration Permit (PEP) 38738

Figure S-2 Daily Company Gross Barrels of Oil Equivalent (BOE) Forecast

Figure S-3 Annual Cash Flow (Before Income Tax)

Figure S-4 Net Present Values (Before Income Tax)

Discussion

General

Geophysics

Geology

Estimation of Reserves and Production Forecasts

Pricing

Operating and Capital Costs

Royalties and TaxesNet Present Values

Table 1 Cheal, New Zealand, Volumetric Reservoir Data and

Estimates of Reserves

Table 2 Cheal, New Zealand, Estimates of Reserves and

Net Present Values

Table 3 Forecasts of Production and Net Revenue

Total Proved Plus Probable Plus Possible Reserves

Table 3A Forecasts of Production and Net Revenue


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Introduction Page 1

Introduction

This report was prepared by Sproule International Limited (Sproule) at the request of Mr.

Garth Johnson, CEO, CFO, Director, Corporate Secretary, Tag Oil Ltd. Tag Oil Ltd. is

hereinafter referred to as "the Company." The effective date of this report is December 31,

2008.

The report consists of an evaluation of the P&NG reserves associated with the Company's

interest in the Cheal Field, New Zealand. It was prepared during the months of December

through February for the purpose of evaluating the Companys P&NG reserves according to

Canadian Oil and Gas Evaluation Handbook (COGEH) reserve definitions that are consistent

with the standards of National Instrument 51-101. This report was prepared for the

Companys corporate purposes.

This one volume report consists of an Introduction, Summary, Discussion and Appendices.

The Introduction includes the summary of the evaluation standards and procedures and

pertinent author certificates; the Summary includes high-level summaries of the evaluation;

and the Discussion includes general commentaries pertaining to the evaluation of the P&NG

reserves. Reserves definitions, abbreviations, units, and conversion factors are included in

Appendices A and B.

Field Operations

In the preparation of this evaluation, a field inspection of the properties was not performed.

The relevant engineering data were made available by the Company or obtained from public

sources and the non-confidential files at Sproule. No material information regarding the

reserves evaluation would have been obtained by an on-site visit.

Historical Data, Interests and Burdens

1 All historical production well data test results capital budgets revenue and expense


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Introduction Page 3

Evaluation Results

1. The accuracy of reserves estimates and associated economic analysis is, in part, a

function of the quality and quantity of available data and of engineering and geological

interpretation and judgment. Given the data provided at the time this report was

prepared, the estimates presented herein are considered reasonable. However, they

should be accepted with the understanding that reservoir and financial performance

subsequent to the date of the estimates may necessitate revision. These revisions may

be material.

2. The net present values of the reserves presented in this report simply represent

discounted future cash flow values at several discount rates. Though net present values

form an integral part of fair market value estimations, without consideration for other

economic criteria, they are not to be construed as Sproules opinion of fair market value.

3. The dollar values presented throughout the report are in United States dollars, unless

otherwise stated.

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

BOE Cautionary Statement

BOEs (or McfGEs or other applicable units of equivalency) may be misleading, particularlyif used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl (or An McfGE conversion ratio of 1

bbl:6 Mcf) is based on an energy equivalency conversion method primarily applicable at the

burner tip and does not represent a value equivalency at the wellhead.

Forward-Looking Statements

This report may contain forward-looking statements including expectations of future

production revenues and capital expenditures. Information concerning reserves may also be

deemed to be forward-looking as estimates involve the implied assessment that the

reserves described can be profitably produced in future. These statements are based on

current expectations that involve a number of risks and uncertainties, which could cause


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Introduction Page 4

projections relating to production; costs and expenses, and health, safety and

environmental factors), commodity price and exchange rate fluctuation.

Exclusivity

This report has been prepared for the exclusive use of Tag Oil Ltd. 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 InternationalLimited, and without the complete contents of the report being made available to that party.


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Introduction Page 5

/ /2009 dd/mm/yr

/ /2009 dd/mm/yr

/ /2009 dd/mm/yr

Certification

Report P reparation

The report entitled Evaluation of the P&NG Reserves of Tag Oil Ltd. in the Cheal Area of

New Zealand (As of December 31, 2008) was prepared by the following Sproule personnel:

___________________________________

Donald W. Woods, P.Eng.,Manager, Engineering

Project Leader

___________________________________Sunday O. Edobor, P.Eng.,

Senior Petroleum Engineer

___________________________________

Douglas J. Carsted, P.Geol.Vice-President, Geoscience

Sproule Executive Endorsement

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

___________________________________

John L.Chipperfield, P.Geol.


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Introduction Page 6

Permit to P ractice

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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Introduction Page 7

Certificate

Donald W . Woods, B.Sc. Chemical Engineering, P. Eng.

I, Donald W. Woods, Manager, Engineering, at Sproule International Limited, 900, 140

Fourth Ave SW, Calgary, Alberta, declare the following:

1. I hold the following degrees:a B.Ed. (1973) University of Calgary, Calgary AB, Canada

b. B.Sc. Chemical Engineering (1980) University of Calgary, Calgary AB, Canada

2. I am a registered professional:

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

3. I am a member of the following professional organizations:a. Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA)

b. Petroleum Society of Canadian (PetSoc)

c. Society of Petroleum Engineers (SPE)

d. Society of Petroleum Evaluation Engineers (SPEE)

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

5. My contribution to the report entitled Evaluation of the P&NG Reserves of Tag Oil Ltd. in

the Cheal Area of New Zealand (As of December 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.

6. I have no interest, direct or indirect, nor do I expect to receive any interest, direct or

indirect, in the properties described in the above-named report or in the securities of

Tag Oil Ltd.


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Introduction Page 8

Certificate

Sunday Edobor, B.Sc., P.Eng.

I, Sunday Edobor, Senior Petroleum Engineer of Sproule International Limited, 900, 140

Fourth Ave SW, Calgary, Alberta, declare the following:

1. I hold the following degree:

a. B.Sc. Petroleum Engineering (1986), University of Ibadan, Nigeria


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

3. I am a member of the following professional organizations:a. Association of Professional Engineers, Geologists and Geophysicists of Alberta (APEGGA)


the Cheal Area of New Zealand (As of December 31, 2008) is based on my engineering






Tag Oil Ltd.

Sunday Edobor, P.Eng.


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Introduction Page 9

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


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 Canadian (PetSoc)

e. Canadian Well Logging Society (CWLS)

f. Indonesian Petroleum Association, Professional Division (IPA)



the Cheal Area of New Zealand (As of December 31, 2008) is based on my geological






Tag Oil Ltd.


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Introduction Page 10

Certificate

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

I, John L. Chipperfield, Senior Vice-President and Director of Sproule International 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


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 Canadian (PetSoc)

e. Canadian Well Logging Society (CWLS)

f. Ontario Petroleum Institute (OPI)



the Cheal Area of New Zealand (As of December 31, 2008) is based on my geological






Tag Oil Ltd.


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Summary - Page 1

Summary

Table S-1, on the following page, summarizes our evaluation of the P&NG reserves

associated with the Companys interest in the Cheal Field, New Zealand. The Company has

informed us that their tax pools exceed the forecasted taxable income from the Cheal

property and therefore, income taxes have not been deducted in this report. The effective

date of the evaluation is December 31, 2008. A map showing the location of the Companys

Petroleum Exploration Permit encompassing the Cheal property is included as Figure S-1.

The reserves were estimated deterministically for the proved, proved plus probable, and

proved plus probable plus possible reserves categories. The oil reserves are presented in

thousands of barrels, at stock tank conditions. The pipeline gas reserves are presented in

millions of cubic feet, at base conditions of 14.65 psia and 60 degrees Fahrenheit.

The reserves definitions and ownership classification used in this evaluation are in

accordance with the standards defined by COGEH reserves definitions and are consistent

with NI 51-101. The net present values of the reserves are presented in thousands of

United States dollars, and are based on annual projections of net revenue, which were

discounted at various rates using the mid-period discounting method. The price forecasts

that formed the basis for the revenue projections in the evaluation were based on Sproules

December 31, 2008 pricing model. Table S-2 presents a summary of the forecasts used.Operating and capital costs were escalated at 2 percent per year as set out in Table S-2.

Well abandonment and disconnect costs were included in this report for wells which have

reserves assigned. No allowances for reclamation or salvage values were made.

Summary forecasts of production and cash flow for the various reserves categories are

included as Tables S-3 through S-3B.

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


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Summary - Page 2

Table S-1

Austral Pacific Energy Ltd

Summary of the Evaluation of the Company's P&NG Reserves

In the Cheal Area of New Zealand

(As of December 31, 2008)

Remaining Reserves Net Present ValuesCompany Before Income Taxes (M$)

Gross Gross NetAt

0%

At

5.0%

At

10.0%

At

15.0%

Light/Medium Oil (Mbbl)

Proved 180 55 53 1,315 1,280 1,247 1,216

Probable 315 96 91 3,097 2,871 2,672 2,497

Total (2P) 495 151 144 4,412 4,151 3,919 3,713

Possible 412 126 112 5,415 4,907 4,472 4,096

Total (3P) 907 277 256 9,827 9,058 8,391 7,809

Solution Gas (MMcf) - values included with lt/med oil -

Proved

Probable 350 107 100

Total (2P) 350 107 100

Possible 340 103 92

Total (3P) 690 210 192

GRAND TOTAL (Mboe)

Total Proved 180 55 53 1,315 1,280 1,247 1,216

Total Probable 373 114 108 3,097 2,871 2,672 2,497

Total (2P) 553 169 161 4,412 4,151 3,919 3,713

Total Possible 469 143 127 5,415 4,907 4,472 4,096

Total (P3) 1,022 312 288 9,827 9,058 8,391 7,809


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Summary - Page 3

Table S-2

Summary of Selected Price Forecasts

and Inflation Rate Assumptions

(Effective December 31, 2008)

Year

TAPIS

Malaysia

($US/bbl)

Cheal

Natural Gas (2 )

($US/ Mcf)

Inflation Rate (2 )

(%/Yr)

Historical

2006 70.12 1.5

2007 77.26 22008 104.61 2

Forecast

2009 57.73 1.45 2

2010 67.49 1.45 2

2011 73.69 1.45 2

2012 83.84 1.45 2

2013 96.34 1.45 2

2014 98.26 1.45 2

2015 100.23 1.45 2

2016 102.23 1.45 2

2017 104.28 1.45 2

2018 106.36 1.45 2

2019 108.49 1.45 2

Escalation rate of 2.0% thereafter

(1) Inflation rates for forecasting prices and costs.(2) Gas price was provided by the company


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NZ Economic Summary (Company)TAG 3P (December 31, 2008)

(Nominal values)

NZ Company Economic Indicators::New Zealand R/T (1995)Disc. Rate BT NPV AT NPV BT PIR AT PIR

(%) (M$US) (M$US) (fraction) (fraction)

0 9,827 9,827 3.15 3.15

5.0 9,058 9,058 3.11 3.11

10.0 8,391 8,391 3.06 3.06

15.0 7,809 7,809 3.01 3.01

20.0 7,298 7,298 2.96 2.96

25.0 6,846 6,846 2.90 2.90

AT ROR (%) >800.00

AT Payout (yrs) 0.00

NZComp. Economics (per Unit)::New Zealand R/T (1995)(M$US) (%) ($US/BOE)

Net Revenue 17,763 100.00 61.60

Less:

Bonuses & Fees 0 0.00 0.00

Operating Costs 4,818 27.12 16.71

Tariffs 0 0.00 0.00

Prod & Asset Taxes 0 0.00 0.00

Capital Costs 3,118 17.55 10.81

Other Income/Expense 0 0.00 0.00

Before Tax Cash Flow 9,827 55.33 34.08

Less Income Tax 0 0.00 0.00

After Tax Cash Flow 9,827 55.33 34.08

NZ Prod Summary::New Zealand R/T (1995)

DateOil

/# Wells

Proj.Oil

Rate

Bbl/d

Proj.Oil

Volume

MSTB

Comp.Oil

Volume

MSTB

NetOil

Volume

MSTB

NetOil

Price

$US/Bbl

Proj.Sol'n Gas

Rate

mcf/d

Proj.Sol'n Gas

Volume

MMSCF

Comp.Sol'n Gas

Volume

MMSCF

NetSol'n Gas

Volume

MMSCF

NetSol'n Gas

Price

$US/mcf2009(12)

2010(12)

2011(12)

2012(12)

2013(12)

Total

6.3

8.0

9.0

9.0

9.0

---

751.5

954.9

473.9

215.8

105.0

---

274

349

173

79

32

907

84

106

53

24

10

277

79

101

45

21

10

256

57.73

67.49

73.69

83.84

96.34

---

504.4

763.9

379.1

172.7

84.0

---

184

279

138

63

26

690

56

85

42

19

8

210

52

80

35

17

8

192

1.45

1.48

1.51

1.54

1.57

---

NZ Comp Cash Flow::New Zealand R/T (1995)

DateWI

BOE Rate

BOE/d

WITotal

BOE Prod

MSTB

Price / BOE

$US/Bbl

SalesRevenue

Total

M$US

RoyaltyTotal

M$US

OperatingCosts

M$US

CapitalCosts

M$US

CapitalAband.

Total

M$US

Before TaxCash Flow

M$US

IncomeTaxes

M$US

After TaxCash Flow

M$US2009(12)

2010(12)

2011(12)

2012(12)

2013(12)

Total

255

330

164

75

36

---

93.0

120.5

59.8

27.3

11.0

311.6

52.10

60.74

66.23

75.21

86.26

---

4,922

7,318

3,960

2,054

952

19,205

246

366

591

239

0

1,442

1,102

1,245

978

839

654

4,818

1,761

821

0

0

0

2,583

0

0

0

0

535

535

1,813

4,886

2,390

976

-238

9,827

0

0

0

0

0

0

1,813

4,886

2,390

976

-238

9,827

Table S - 3


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NZ Economic Summary (Company)Tag 2P (December 31, 2008)

(Nominal values)



0 4,412 4,412 2.50 2.50

5.0 4,151 4,151 2.48 2.48

10.0 3,919 3,919 2.45 2.45

15.0 3,713 3,713 2.42 2.42

20.0 3,527 3,527 2.39 2.39

25.0 3,360 3,360 2.36 2.36

AT ROR (%) >800.00AT Payout (yrs) 0.00


Net Revenue 9,479 100.00 59.10

Less:



Tariffs 0 0.00 0.00


Capital Costs 1,763 18.59 10.99






DateOil

/# Wells

Proj.Oil

Rate

Bbl/d

Proj.Oil

Volume

MSTB

Comp.Oil

Volume

MSTB

NetOil

Volume

MSTB

NetOil

Price

$US/Bbl

Proj.Sol'n Gas

Rate

mcf/d

Proj.Sol'n Gas

Volume

MMSCF

Comp.Sol'n Gas

Volume

MMSCF

NetSol'n Gas

Volume

MMSCF

NetSol'n Gas

Price

$US/mcf2009(12)

2010(12)

2011(12)

2012(12)

Total

6.3

7.6

8.0

8.0

---

623.5

465.1

199.3

101.2

---

228

170

73

25

495

69

52

22

8

151

66

49

21

8

144

57.73

67.49

73.69

83.84

---

374.0

372.1

159.4

81.0

---

137

136

58

20

350

42

41

18

6

107

38

39

17

6

100

1.45

1.45

1.45

1.45

---


DateWI

BOE Rate

BOE/d

WITotal

BOE Prod

MSTB

Price / BOE

$US/Bbl

SalesRevenue

Total

M$US

RoyaltyTotal

M$US

OperatingCosts

M$US

CapitalCosts

M$US

CapitalAband.

Total

M$US

Before TaxCash Flow

M$US

IncomeTaxes

M$US

After TaxCash Flow

M$US2009(12)

2010(12)

2011(12)

2012(12)

Total

209

161

69

35

---

76.4

58.7

25.1

8.5

168.7

52.10

60.72

66.18

75.13

---

4,076

3,563

1,664

641

9,944

204

178

83

0

465

1,027

954

812

512

3,305

1,359

0

0

0

1,359

0

0

200

204

404

1,486

2,431

569

-74

4,412

0

0

0

0

0

1,486

2,431

569

-74

4,412

Table S - 3A


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(Nominal values)



0 1,315 1,315 3.91 3.91

5.0 1,280 1,280 4.10 4.10

10.0 1,247 1,247 4.28 4.28

15.0 1,216 1,216 4.46 4.46

20.0 1,188 1,188 4.65 4.65

25.0 1,161 1,161 4.83 4.83



Net Revenue 3,226 100.00 60.81

Less:



Tariffs 0 0.00 0.00


Capital Costs 336 10.42 6.34






DateOil

/# Wells

Proj.Oil

Rate

Bbl/d

Proj.Oil

Volume

MSTB

Comp.Oil

Volume

MSTB

NetOil

Volume

MSTB

NetOil

Price

$US/Bbl

Proj.Sol'n Gas

Rate

mcf/d

Proj.Sol'n Gas

Volume

MMSCF

Comp.Sol'n Gas

Volume

MMSCF

NetSol'n Gas

Volume

MMSCF

NetSol'n Gas

Price

$US/mcf2009(12)

2010(12)

Total

6.0

6.0

---

343.2

164.5

---

125

55

180

38

17

55

36

17

53

57.73

67.49

---

0.0

0.0

---

0

0

0

0

0

0

0

0

0

0.00

0.00

---


DateWI

BOE Rate

BOE/d

WITotal

BOE Prod

MSTB

Price / BOE

$US/Bbl

SalesRevenue

Total

M$US

RoyaltyTotal

M$US

OperatingCosts

M$US

CapitalCosts

M$US

CapitalAband.

Total

M$US

Before TaxCash Flow

M$US

IncomeTaxes

M$US

After TaxCash Flow

M$US2009(12)

2010(12)

Total

105

50

---

38.2

16.8

55.0

57.73

67.49

---

2,205

1,131

3,337

110

0

110

864

711

1,575

0

0

0

0

336

336

1,231

85

1,315

0

0

0

1,231

85

1,315

Table S - 3B

Figure S-1


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Figure S 1

2 0 50 0 00 2 1 00 0 00 2 1 50 0 00 2 2 00 0 00 2 2 50 0 00 2 3 00 0 00 2 3 50 0 00 2 4 00 0 00 2 4 50 0 00 2 5 00 0 00 2 5 50 0 00 2 6 00 0 00 2 6 50 0 00 2 7 00 0 00 2 7 50 0 00 2 8 00 0 00 2 8 50 0 00 2 9 00 0 00 2 9 50 0 00 3 0 00 0 00

5200000

5250000

5300000

5350000

5400000

5450000

5500000

5550000

5600000

5650000

5700000

5750000

5800000

5850000

5900000

5950000

6000000

6050000

6100000

6150000

6200000

6250000

6300000

6350000

6400000

6450000

6500000

6550000

6600000

6650000

6700000

Cardiff

Cheal

PEP 3873847.6 square miles

Figure S-2


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Figure S 2

0

50

100

150

200

250

300

350

2009 2010 2011 2012 2013

YEAR

Proved Plus Probable Plus Possile Proved Plus Probable Proved

DAILYEQUIVALENT(BOE)F

ORECASTboep

d

Figure S-3


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g

-1000

0

1000

2000

3000

4000

5000

2009 2010 2011 2012 2013

YEAR


ANNUAL

CASHFLOW

PROJE

CTIONSM$US

Figure S-4


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0

2000

4000

6000

8000

10000

5 10 15 20 25

DISCOUNT RATES (%)

NETP

RESENT

VAL

UE

-M$US



26/55

Discussion - Page 1

Discussion

1.0 General

The Companys reserves are associated with the Cheal Field, New Zealand. The field is

located in the onshore portion of the Taranaki Basin, which lies along the west coast of the

North Island (Figure 1). The basin, which contains Cretaceous to Recent sediments, covers

an area of some 32,800 square miles, most of which lies offshore.

The Company owns a 30.5% working interest in the shallow rights of PEP 38738. The

shallow rights include all strata from Recent to base of Miocene, which encompasses the

Intra Urenui and Mt. Messenger reservoirs in the Cheal Field.

The Cheal structure has been penetrated by a total of nine wells, Cheal-1, 2, A3X, A4, A6,

A7, B1, B2 and B3. Eight of these wells encountered oil pay of which six are currently on

production with a cumulative oil volume of 429 Mbbl. The three wells drilled from the B-Padlocation were drilled in 2006 and put on production throughout 2007. An additional well,

Cheal B4, was drilled outside of the current pool boundaries; however, no reserves have

been assigned to this well. Two new wells, Cheal-A6 and A7, were drilled from the A-pad

location. The A6 well and the subsequent sidetrack A6ST1 did not encounter sufficient

reservoir quality sand to be productive and were abandoned. Well A7 intersected oil pay in

the Mt. Messenger 2 Sandstone and was cased as a future producer. Permanent facilities

and gathering systems have been installed and commissioned in the field.

No new data which would allow reserves to be assigned to the Urenui reservoir has been

provided at this time.

2.0 Geophysics

Data Control

Over the past year, no additional seismic data has been acquired over the Cheal Field. Data

from the two new wells resulted in minor changes to the structural interpretation. Figure 2

shows the outline of PEP 38738 and the location of the Cheal Field with respect to the 2D


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Discussion - Page 2

Geophysical Interpretation

Figure 3 presents a perspective view, looking west, of the depth structure on the top of the

Mt. Messenger Sandstone 3, showing the well penetrations and interpreted faults. The main

bounding fault on the western flank of the field is intersected by a series of SSW-NNE

trending splay faults in the vicinity of the field. The magenta colored fault in this figure can

be seen to separate the wells of the A Block (Cheal-1, 2, A3X, A4, A6, A6ST1, and A7) from

those of the B Block (Cheal-B1, B2 and B3).

A multi-layer depth conversion was conducted within Petrel to convert from time to depth

using the well control. Figure 4 shows the well tops and the depth structure at the Mt.

Messenger Sandstone 3. Depth structure maps on Sandstone 3 and Sandstone 2 are

provided in Figures 5 and 6, respectively.

3.0 Geology

Cheal-1 was drilled in 1995 by New Zealand Oil & Gas Services Ltd. Good oil and gas shows

led to the testing of the Urenui Formation. This formation was tested over a nine-day period

at a steady rate of 48 bopd, with gas declining from 2.7 MMscfd to 1.05 MMscfd. The Mt.

Messenger Formation was not tested in this well, although shows and petrophysical analysis

indicate approximately 16 feet of net pay. The Urenui Formation was further tested for 1.2

days in December 2005 at 0.14 MMscfd of gas, with no oil reported.

Cheal-2 was drilled in 1995 by New Zealand Oil & Gas Services Ltd. as a step-out to Cheal-

1. The well was tested over the Intra Urenui Sandstone for a period of 6 days and flowed at

initial rates of 1.8 MMscfd of gas with slugs of oil. The gas rates declined to 0.9 MMscfd

with oil rates of approximately 20 bopd. No water was produced during the test.

Petrophysical analysis indicates that the Mt. Messenger Sandstone is wet in this well and

defines the limits of the pool to the east. The Company plans to convert this well to water

disposal.

Cheal-A3X was drilled in April 2004 to test the hydrocarbon potential of the Intra Urenui and

Mt. Messenger sandstones in an updip position from the Cheal-1 and Cheal-2 wells. This


28/55

Discussion - Page 3

tested from May to August 2005, at an average oil rate of 350 bopd with gas-oil ratios

increasing from 475 to 825 scf/bbl. Water-cuts were less than one percent.

The Company subsequently participated in the drilling of Cheal-A4 in October 2004 to

further evaluate the hydrocarbon potential of the Intra Urenui and Mt. Messenger

sandstones. This well was directionally drilled from the Cheal A pad toward the NE,

intersecting the target horizons approximately halfway between the Cheal A3X well and the

downdip Cheal-2 well. The well was completed in the uppermost Intra Urenui Formation and

the Mt. Messenger Formation. It was tested from the Mt. Messenger Formation fromNovember 2004 to May 2005 and from September 2005 to December 2005. Over this

period, oil production averaged 265 bopd with gas-oil ratios increasing from 500 to 730

scf/bbl. Water-cuts had increased to 24 percent by December 2005. The Urenui Formation

was also tested in April, May, October and November 2005 at gas rates of 0.1 to 1.1 MMscfd

with very little oil.

During October and November 2006, the Company participated in the drilling of three

deviated wells (Cheal-B1, B2 and B3) from the Cheal B pad, approximately 0.8 miles to the

north of the Cheal A pad. All three wells intersected the Mt. Messenger sandstones north of

the northeast-southwest trending fault that transects the field. From petrophysical analysis,

Cheal B-1 and Cheal B-3 intersected the thicker and better quality Mt. Messenger

sandstones. Cheal B-2 encountered only about 6 feet of net pay in the Mt. Messenger

Sandstone 3, but did encounter 16 feet of net pay in the Mt. Messenger Sandstone 2.

During 2008, the Company drilled two new wells, Cheal-A6 and A7. The A6 well did not

encounter reservoir quality sandstone within the Mt. Messenger. It was subsequently

sidetracked towards the south, however, the sidetrack also did not encounter sufficient net

pay to be productive. The A7 well, drilled to the north and east of A6, did encounter

productive Mt. Messenger sandstones. This new well data resulted in changes to the net pay

maps previously drawn using the well data available at the end of 2007, which resulted in a

decrease in OOIP for the field.

The oil-water contact established for the Mt. Messenger Sandstone 3 in the A pad wells is

4,605 feet subsea (-1404m), while the B fault block wells did not encounter an oil-water

contact but established an oil-down-to elevation of 4,592 feet subsea (-1400m). This oil-

Di i P 4


29/55

Discussion - Page 4

reservoir has been classified as probable, because the reservoir has not been tested in the B

fault block, which contains the majority of the in-place oil volumes.

The net pay maps used to estimate the original oil-in-place were generated from a 3D

geological model and are displayed in Figures 7 and 8 for the Mt. Messenger Sandstones 3

and 2, respectively. The location of the Cheal B4 well, shown on Figure 7, is the projected

intersection of the well at the Mt. Messenger Sandstone 3 level. The well did not encounter

a Mt. Messenger 3 sandstone at this location.

4.0 Estimation of Reserves and Production Forecasts

Oil reserves were estimated volumetrically for the Mt. Messenger Formation using

volumetric data from Petrel model and net pay thicknesses based on well logs and seismic

interpretation. Reservoir porosity and water saturation were obtained from well logs.

Eight productive wells have been drilled in the Cheal Field. Six out of the eight wells are

currently on production, with cumulative production of 429 Mbbl. Proved, probable and

possible reserves were assigned to the producing wells. The company plans to fracture

stimulate all six producing wells and this is expected to result in improved oil rate and

incremental reserves. The incremental reserves associated with wells B1 and B3 were

booked as probable. The incremental reserves associated with wells B2, A1, A4 and A7 were

booked in the possible category since the fracturing of these wells depends on the success

of B1 and B3.

Probable and possible reserves were also assigned to two undrilled locations, B4 and B5. A

third location, B7, which will be drilled if B4 and B5 are successful, was assigned possible

reserves.

Recovery factors were estimated to be 8.5 percent in the proved (1P) case, 10 percent in

the proved plus probable (2P) case and 12 percent in the proved plus probable plus possible

(3P) case. These recovery factors are based on the production performance of the existing

wells in the field. These recovery factors are lower than those estimated previously, which

were based on analogue field data and early production results from the Cheal wells.

Discussion Page 5


30/55

Discussion - Page 5

5.0 Pricing

Sproules short-term outlook for oil prices adopts the NYMEX futures market for the forecast

period ending December 31, 2011. The forecast used in this evaluation was derived as of

December 31, 2008, and reflects the arithmetic average of the futures market at the close

of trading each day, for the month prior to the Termination of Trading date for a January

2009 contract. The oil price forecasts are based on the NYMEX Division light, sweet (low-

sulphur) crude oil futures contract, which specifies the West Texas Intermediate crude as a

deliverable. Sproule then applies a historical offset to generate the Tapis forecast.

The NYMEX oil futures prices are the foundation of Sproules energy pricing models in the

early years. This data is combined with Sproules assumptions respecting long-term prices,

inflation rates, and exchange rates, together with estimates of transportation costs and

prices of competing fuels, to forecast wellhead prices for oil production. The following

paragraphs briefly describe some of the key considerations included in Sproules long-term

outlook for oil price forecasts.

In the long term, the price of oil will be governed by supply and demand, and the degree

that OPEC is able to manage supply will be a major determinant in establishing oil prices in

the future. Crude oil demand, world economy conditions and the cost of exploration and

development generally served to determine the price of crude oil throughout the world. In

recognition of these factors, Sproule's long-term forecast for Tapis has been set at $US 89

per barrel (2009 dollars).

The oil price forecasts are based on a forecast of prices for Tapis crude. The actual wellhead

price of oil will vary with the quality of the crude and the cost of the transportation from the

wellhead to the delivery point. The Company instructed us to use the Sproule Tapis

(Malaysia) crude price forecast in the evaluation without an offset for quality or

transportation.

Discussion - Page 6


31/55

Discussion - Page 6

6.0 Operating and Capital Costs

The Company provided estimates of capital investments and operating expenses required to

continue development and operation of the field. A fixed costs of US$ 181,500 per month

and variable costs of US$ 5.24 per barrel, which include trucking, shipping and handling,

were used in the evaluation.

The capital costs used in the evaluation are summarized below. All wells are scheduled to be

fracture stimulated at a cost of US$ 220,000 per well. Three wells are scheduled to bedrilled and completed at a total cost of US$ 6.44MM.

Well abandonment and disconnect costs of US$ 180,000 per well was used. No allowances

for reclamation or salvage values were made.

Capital Costs US$M (2009 Dollars)

Probable Possible

Date FracNewDrill Frac

NewDrill Comments

March 2009 440 440 Frac B1 and B3

June 2009 1,595 1,595 Drill & tie in B4

July 2009 1,100

Frac A3, A4, A7, B2 andB4, if B1& B3 fracs are

successfulOctober 2009 2,420 2,420 Drill & tie in B5

November 2009 220 Frac B5

February 2010 2,420 Drill & tie in B6

March 2010 220 Frac B6

Total 440 4,015 1980 6,435

Operating and capital costs were escalated at 2.0 percent per year.

7.0 Royalties and Taxes

The Companys tax pool of 5 7 million US Dollars was included as input to this evaluation;

Discussion - Page 7


32/55

Discussion Page 7

any given year. The AVR is calculated at five percent of the net sales price received. The

APR is a mechanism whereby the resource owner receives a share of profits once allsignificant costs have been recovered by the producer. It is payable on the net accumulated

accounting profit of production from a petroleum field. In calculating the accounting profit,

deductions are made and may include associated production costs, capital costs (exploration

costs, development costs, permit acquisition costs and feasibility costs), indirect costs,

abandonment costs, operating and capital overhead allowance, operating costs and capital

costs carried forward and abandonment costs carried back. The APR royalty was calculated

from forecasts of cash flow. A Net Allowable Deduction in the sum of 6.7 million US$ or 12New Zealand Dollars was carried forward from 2008. This deduction was used in the Royalty

calculations. This resulted in an AVR Royalty regime for the 1P, 2P and for the first two

years in the 3P case. The APR Royalty Regime was then applied for the third and fourth

year in the 3P case.

8.0 Net Present Values

The estimates of the P&NG reserves and their respective net present values, summarized by

reserves category, are presented in Tables 1 and 2. Detailed forecasts of production and

cash flow are presented in Tables 3 to 3B. Well abandonment and disconnect costs were

included for wells which have reserves assigned. No allowances for reclamation or salvage

values were made.


33/55

(ac) (ft) (%) (%) RB/STB Mbbls % Mbbls

Cheal A Block*

Proved Lands

Mount Messenger 3

PDP 211 18.8 23 37 1.22 3,663

2P 211 18.8 23 37 1.22 3,663

3P 211 18.8 23 37 1.22 3,663

Mount Messenger 2

PDP 96 9.8 21 46 1.22 684

2P 96 9.8 21 46 1.22 684

3P 96 9.8 21 46 1.22 684

Cheal B Block**

Proved Lands

Mount Messenger 3

PDP 128 23.9 23 37 1.22 2,8232P 128 23.9 23 37 1.22 2,823

3P 128 23.9 23 37 1.22 2,823

Mount Messenger 2

PDP 85 9.5 21 46 1.22 551

2P 85 9.5 21 46 1.22 551

3P 85 9.5 21 46 1.22 551

Probable Lands

Mount Messenger 3

2P 88 22.57 23 37 1.22 1,830

3P 88 22.57 23 37 1.22 1,830Possible Lands

Mount Messenger 3

3P 86 17.89 23 37 1.22 1,422

Mount Messenger 2

3P 54 7.04 21 46 1.22 294

Field Total

Proved Developed Producing 520 16.90 22 40 1.22 7,720 8.5 656

Proved + Probable 608 17.70 22 40 1.22 9,550 10 955Proved + Probable + Possible 748 15.70 22 40 1.22 11,266 12 1,352

* Cheal A3, A4 and A7 producing wells, commingled in the MM2 and MM3 zones.

**Cheal B1, B2 and B3 producing wells, commingled in the MM2 and MM3 zones. Undriilled locations B4, B5 and B6.

Table 1

Cheal, New Zealand

Volumetric Reservoir Data and Estimates of Reserves

(As of December 31, 2008)

Pool/Location

Drainage

AreaNet Pay Porosity

Original

Recoverable Oil

Water

Saturation

Oil

FVF

Original Oil

In Place

Recovery

Factor


34/55

Mbbls % Mbbls Mbbls Mbbls (%) Mbbls (%) Mbbls 0% 5% 10% 15% 20%

Cheal A Block*

Proved Lands

Mount Messenger 3

PDP 3,663

2P 3,663

3P 3,663

Mount Messenger 2

PDP 684

2P 684

3P 684

Cheal B Block**

Proved Lands

Mount Messenger 3

PDP 2,823

2P 2,823

3P 2,823

Mount Messenger 2

PDP 551

2P 551

3P 551

Probable Lands

Mount Messenger 3

2P 1,830

3P 1,830

Possible Lands

Mount Messenger 3

3P 1,422

Mount Messenger 2

3P 294

Field Total

Proved Developed Producing 7,720 8.5 656 429 227 180 69.5 55 AVR/APR 53 1,315 1,280 1,247 1,216 1,188

Proved + Probable 9,550 10 955 429 526 495 69.5 151 AVR/APR 144 4,412 4,151 3,919 3,713 3,527

Proved + Probable + Possible 11,266 12 1,352 429 923 907 69.5 277 AVR/APR 256 9,827 9,058 8,391 7,809 7,298



Company

Net

OilRecoves

Recovery

Factor

Company

WorkingInterest

Company

Gross

(Economic)Oil Reserves

Lessor

Royaltiesand Burden

Total Field

Economic

Reserves(100%)

Original Oil

In Place

Net Present Values

Before Taxes(USM$)

Table 2Cheal, New Zealand

Estimates of Reserves and Net Present Values(As of December 31, 2008)

Cum Prod

Oil to Dec.31, 2008

Total Field

Technical

Reserves(100%Pool/Location

Original

RecoverableOil


35/55

scf/bbl MMcf (%) MMcf (%) Mbbls 0% 5% 10% 15% 20%

Cheal A Block*

Proved Lands

Mount Messenger 3

PDP

2P

3P

Mount Messenger 2PDP

2P

3P

Cheal B Block**

Proved Lands

Mount Messenger 3

PDP

2P

3P

Mount Messenger 2

PDP

2P3P

Probable Lands

Mount Messenger 3

2P

3P

Possible Lands

Mount Messenger 3

3P

Mount Messenger 2

3P

Field Total

Proved Developed Producing No sales Gas booked for the PDP category

Proved + Probable 350 69.5 107 AVR/APR 100 Values included with Oil Reserves

Proved + Probable + Possible 690 69.5 210 AVR/APR 192 Values included with Oil Reserves



Table 2Cheal, New Zealand

Estimates of Reserves and Net Present Values(As of December 31, 2008)

Net Present Values

Before TaxesPool/Location

Producing Gas

Oil Ratio

Tota Field

Economic GasReserves

(100%)

CompanyWorking

Interest

Producing

GORof 800

scf/bbl

CompanyEconomic Gas

Reserves

LessorRoyalties and

Burden

CompanyNet

Gas

Recoves


36/55

NZ Economic Summary (Company)TAG 3P (December 31, 2008)

(Nominal values)



0 9,827 9,827 3.15 3.15

5.0 9,058 9,058 3.11 3.11

10.0 8,391 8,391 3.06 3.06

15.0 7,809 7,809 3.01 3.01

20.0 7,298 7,298 2.96 2.96

25.0 6,846 6,846 2.90 2.90



Net Revenue 17,763 100.00 61.60

Less:



Tariffs 0 0.00 0.00


Capital Costs 3,118 17.55 10.81






DateOil

/# Wells

Proj.Oil

Rate

Bbl/d

Proj.Oil

Volume

MSTB

Comp.Oil

Volume

MSTB

NetOil

Volume

MSTB

NetOil

Price

$US/Bbl

Proj.Sol'n Gas

Rate

mcf/d

Proj.Sol'n Gas

Volume

MMSCF

Comp.Sol'n Gas

Volume

MMSCF

NetSol'n Gas

Volume

MMSCF

NetSol'n Gas

Price

$US/mcf2009(12)

2010(12)

2011(12)

2012(12)

2013(12)

Total

6.3

8.0

9.0

9.0

9.0

---

751.5

954.9

473.9

215.8

105.0

---

274

349

173

79

32

907

84

106

53

24

10

277

79

101

45

21

10

256

57.73

67.49

73.69

83.84

96.34

---

504.4

763.9

379.1

172.7

84.0

---

184

279

138

63

26

690

56

85

42

19

8

210

52

80

35

17

8

192

1.45

1.48

1.51

1.54

1.57

---


DateWI

BOE Rate

BOE/d

WI

TotalBOE Prod

MSTB

Price / BOE

$US/Bbl

Sales

RevenueTotal

M$US

RoyaltyTotal

M$US

OperatingCosts

M$US

CapitalCosts

M$US

Capital

Aband.Total

M$US

Before TaxCash Flow

M$US

IncomeTaxes

M$US

After TaxCash Flow

M$US2009(12)

2010(12)

2011(12)

2012(12)

2013(12)

Total

255

330

164

75

36

---

93.0

120.5

59.8

27.3

11.0

311.6

52.10

60.74

66.23

75.21

86.26

---

4,922

7,318

3,960

2,054

952

19,205

246

366

591

239

0

1,442

1,102

1,245

978

839

654

4,818

1,761

821

0

0

0

2,583

0

0

0

0

535

535

1,813

4,886

2,390

976

-238

9,827

0

0

0

0

0

0

1,813

4,886

2,390

976

-238

9,827

Table 3


37/55


38/55


(Nominal values)



0 4,412 4,412 2.50 2.50

5.0 4,151 4,151 2.48 2.48

10.0 3,919 3,919 2.45 2.45

15.0 3,713 3,713 2.42 2.42

20.0 3,527 3,527 2.39 2.39

25.0 3,360 3,360 2.36 2.36



Net Revenue 9,479 100.00 59.10

Less:



Tariffs 0 0.00 0.00


Capital Costs 1,763 18.59 10.99






DateOil

/# Wells

Proj.Oil

Rate

Bbl/d

Proj.Oil

Volume

MSTB

Comp.Oil

Volume

MSTB

NetOil

Volume

MSTB

NetOil

Price

$US/Bbl

Proj.Sol'n Gas

Rate

mcf/d

Proj.Sol'n Gas

Volume

MMSCF

Comp.Sol'n Gas

Volume

MMSCF

NetSol'n Gas

Volume

MMSCF

NetSol'n Gas

Price

$US/mcf2009(12)

2010(12)

2011(12)

2012(12)

Total

6.3

7.6

8.0

8.0

---

623.5

465.1

199.3

101.2

---

228

170

73

25

495

69

52

22

8

151

66

49

21

8

144

57.73

67.49

73.69

83.84

---

374.0

372.1

159.4

81.0

---

137

136

58

20

350

42

41

18

6

107

38

39

17

6

100

1.45

1.45

1.45

1.45

---


Date

WI

BOE RateBOE/d

WITotal

BOE ProdMSTB

Price / BOE$US/Bbl

SalesRevenue

TotalM$US

Royalty

TotalM$US

Operating

CostsM$US

Capital

CostsM$US

CapitalAband.

TotalM$US

Before Tax

Cash FlowM$US

Income

TaxesM$US

After Tax

Cash FlowM$US

2009(12)

2010(12)

2011(12)

2012(12)

Total

209

161

69

35

---

76.4

58.7

25.1

8.5

168.7

52.10

60.72

66.18

75.13

---

4,076

3,563

1,664

641

9,944

204

178

83

0

465

1,027

954

812

512

3,305

1,359

0

0

0

1,359

0

0

200

204

404

1,486

2,431

569

-74

4,412

0

0

0

0

0

1,486

2,431

569

-74

4,412

Table 3A


39/55

Comp Royalty TotalTag 2P (December 31, 2008)

(Nominal values)

DateRoyalty

AVR

M$US

RoyaltyAPR

M$US

RoyaltyTotal

(Max)

M$US

SalesRevSplit

Oil/Total

%

RoyaltyOil

M$US

SalesRevSplit

Gas/Total

%

RoyaltyGas

M$US

SalesRevSplit

NGL/Total

%

RoyaltyNGL

M$US2009(12)

2010(12)

2011(12)

2012(12)

Total

204

178

83

0

465

0

0

0

0

0

204

178

83

0

465

98.50

98.09

98.24

98.45

---

199

175

82

0

456

1.50

1.91

1.76

1.55

---

5

3

1

0

9

0.00

0.00

0.00

0.00

---

0

0

0

0

0

Table 3A


40/55


(Nominal values)



0 1,315 1,315 3.91 3.91

5.0 1,280 1,280 4.10 4.10

10.0 1,247 1,247 4.28 4.28

15.0 1,216 1,216 4.46 4.46

20.0 1,188 1,188 4.65 4.65

25.0 1,161 1,161 4.83 4.83



Net Revenue 3,226 100.00 60.81

Less:



Tariffs 0 0.00 0.00


Capital Costs 336 10.42 6.34






DateOil

/# Wells

Proj.Oil

Rate

Bbl/d

Proj.Oil

Volume

MSTB

Comp.Oil

Volume

MSTB

NetOil

Volume

MSTB

NetOil

Price

$US/Bbl

Proj.Sol'n Gas

Rate

mcf/d

Proj.Sol'n Gas

Volume

MMSCF

Comp.Sol'n Gas

Volume

MMSCF

NetSol'n Gas

Volume

MMSCF

NetSol'n Gas

Price

$US/mcf2009(12)2010(12)

Total

6.06.0

---

343.2164.5

---

12555

180

3817

55

3617

53

57.7367.49

---

0.00.0

---

00

0

00

0

00

0

0.000.00

---


DateWI

BOE Rate

BOE/d

WITotal

BOE Prod

MSTB

Price / BOE

$US/Bbl

SalesRevenue

Total

M$US

RoyaltyTotal

M$US

OperatingCosts

M$US

CapitalCosts

M$US

CapitalAband.

Total

M$US

Before TaxCash Flow

M$US

IncomeTaxes

M$US

After TaxCash Flow

M$US

2009(12)2010(12)

Total

10550

---

38.216.8

55.0

57.7367.49

---

2,2051,131

3,337

1100

110

864711

1,575

00

0

0336

336

1,23185

1,315

00

0

1,23185

1,315

Table 3B


41/55

Figure 1


42/55

2 0 50 0 00 2 1 00 0 00 2 1 50 0 00 2 2 00 0 00 2 2 50 0 00 2 3 00 0 00 2 3 50 0 00 2 4 00 0 00 2 4 50 0 00 2 5 00 0 00 2 5 50 0 00 2 6 00 0 00 2 6 50 0 00 2 7 00 0 00 2 7 50 0 00 2 8 00 0 00 2 8 50 0 00 2 9 00 0 00 2 9 50 0 00 3 0 00 0 00

5200000

5250000

5300000

5350000

5400000

5450000

5500000

5550000

5600000

5650000

5700000

5750000

5800000

5850000

5900000

5950000

6000000

6050000

6100000

6150000

6200000

6250000

6300000

6350000

6400000

6450000

6500000

6550000

6600000

6650000

6700000

Cardiff

Cheal

PEP 38738

47.6 square miles

Figure 2


43/55

3D seismic

PEP 38738

Stratford-1 well

Cardiff Field

Cheal Field


44/55

Figure

370535

Cheal Field-Depth Structure at Sandstone 3 with Fault Framework Interpreted by Sproule

Need updated graph

Block ABlock B


45/55

Fig

ure

470535

Cheal Field-Depth Structure at Sandstone 3 with Well Tops

Need updated graph

Well

Tops


46/55

Fig

ure

570535

Cheal Field Mt. Messenger Sandstone 3 Depth Structure Map


47/55

Fig

ure

670535

Cheal Field Mt. Messenger Sandstone 2 Depth Structure Map


48/55

Fig

ure

770535

Cheal Field Mt. Messenger Sandstone 3 Net pay Map


49/55

Fig

ure

870535

Cheal Field Mt. Messenger Sandstone 2 Net pay Map


50/55

Fig

ure

970535


51/55

Figu

re

10

70535


52/55

Figu

re

11

70535


53/55

Figu

re

12

70535


54/55

Figu

re

13

70535


55/55

Figu

re

14

70535

tag sproulereport 12-31-08

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