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EX-99.1 3 report.htm TECHNICAL REPORT - EVALUATION OF THE GAS AND CONDENSATE RESERVES OF INDO-PACIFIC ENERGY LIMITED IN THE KAHILI FIELD OF NEW ZEALAND (AS OF OCTOBER 1, 2003) Filed by Automated Filing Services Inc. (604) 609-0244 - Indo-Pacific Energy Limited - Evaluation report

EVALUATION OF THE GAS AND CONDENSATE RESERVES

INDO-PACIFIC ENERGY LIMITED

IN THE KAHILI FIELD OF NEW ZEALAND

(As of October 1, 2003)

Copies:	Indo-Pacific Energy Limited (5)
	Sproule International Limited (1)
	GDR (1)

Project No.:	3129.70251

Prepared For:	Indo-Pacific Energy Limited

Authors:	G.D. Robinson, P.Eng., Project Leader
	D. J. Carsted, P. Geol.
	F. P. Williams, P. Eng.

Exclusivity:	This report has been prepared for the exclusive use of Indo-Pacific Energy Limited, and shall not be reproduced, distributed, or made available to any other company or person, regulatory body, or organization without the knowledge and written consent of Sproule International Limited, and without the complete contents of the report.

Table of Contents — Page 1

Table of Contents

Introduction
	Disclaimer
	Certification

Summary

Table S-1	Summary of the Evaluation of the Gas and Condensate Reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand As of October 1, 2003, U.S. Dollars Forecast Prices and Costs

Table S-2	Summary of the Evaluation of the Gas and Condensate Reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand As of October 1, 2003, U.S. Dollars Constant Prices and Costs

Table S-3	Table S-3 – Kahili – 1b, New Zealand, 45% Working Interest, Total Proven Undeveloped Plus Probable Reserves As of October 1, 2003 – Forecast Prices and Costs, US Dollars

Table S-4	Table S-3 – Kahili – 1b, New Zealand, 45% Working Interest, Proven Undeveloped As of October 1, 2003 – Forecast Prices and Costs, US Dollars

Table S-5	Table S-3 – Kahili – 1b, New Zealand, 45% Working Interest, Probable Reserves As of October 1, 2003 – Forecast Prices and Costs, US Dollars

	Sproule

Table of Contents — Page 2

Table S-6	Table S-3 – Kahili – 1b, New Zealand, 45% Working Interest, Proven Undeveloped As of October 1, 2003 – Constant Prices and Costs, US Dollars

Figure S-1	Location Map

Discussion

1.0	General
2.0	Geology
3.0	Estimation of Reserves
4.0	Gas Contract
5.0	Deliverability Modeling
6.0	Production Forecasts
7.0	Petroleum Royalty Regime
8.0	Operating and Capital Costs
9.0	Pricing
10.0	Net Present Values

Table 1	Kahili, New Zealand, Volumetric Reservoir Data

Table 2	Kahili, New Zealand, Estimates of Reserves and Net Present Values using Forecast Prices and Costs (As of October 1, 2003)

Table 3	Kahili – 1b, New Zealand, 45% Working Interest, Total Proven Undeveloped Plus Probable Reserves, As of October 1, 2003, Forecast Prices and Costs, US Dollars

Table 4	Kahili – 1b, New Zealand, 45% Working Interest, Proven Undeveloped As of October 1, 2003, Forecast Prices and Costs, US Dollars

	Sproule

Table of Contents — Page 3

Table 5
Kahili – 1b, New Zealand, 45% Working Interest, Probable Reserves, As of October 1, 2003, Forecast Prices and Costs, US Dollars

Table 6
Kahili – 1b, New Zealand, 45% Working Interest, Proven Undeveloped As of October 1, 2003, Constant Prices and Costs, US Dollars

Figure 1 Kahili Field Location Map

Figure 2 Top Tariki Sandstone

Figure 3 Kahili – 1b Well Log Analysis

Appendices

Appendix A Reserves Definitions

Appendix B Abbreviations, Units and Conversion Factors

Appendix C PVT Study

Appendix D Kahibi 1B Facility Development Study

Sproule

October 2003

Introduction — Page 1

INTRODUCTION

This report was prepared by Sproule International Limited (“Sproule”) at the request of Dr. David J. Bennett, CEO, Indo-Pacific Energy Limited. Indo-Pacific Energy Limited is hereinafter referred to as "the Company." The effective date of this report is October 1, 2003. It consists of an independent evaluation of the gas and condensate reserves associated with the Company’s interests in the Kahili Field of New Zealand.

Disclaimer

This report has been prepared by Sproule International Limited using state-of-the-art 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 reserves and values presented in this report could be affected by the data received, and the procedures used, by Sproule International Limited, as qualified below.

Historical Data and Field Operations

1.	All historical production and test data, well data, and the engineering, geological and geophysical data that were obtained from the Company or from public sources were accepted as represented, without any further investigation by Sproule.

2.	In the preparation of this evaluation, a field inspection of the properties was not performed by Sproule. The relevant data were made available by the Company or obtained from public sources and the non-confidential files at Sproule.

Interests and Burdens

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

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. As a well matures and new information becomes available, revisions may be

	Sproule

October 2003

Introduction — Page 2

	required which may either increase or decrease the previous reserve assignments. Sometimes these revisions may result not only in a significant change to the reserves and value assigned to a property, but also may impact the total company reserve and economic status. The reserves and forecasts contained in this report were based upon a technical analysis of the available data using accepted engineering principles. However, they must be accepted with the understanding that further information and future reservoir performance subsequent to the date of the estimate may justify their revision. Sproule makes no warranties concerning the data and interpretations of such data. In no event shall Sproule be liable for any special or consequential damages arising from the Company’s use of Sproule’s interpretation, reports, or services produced as a result of its work for the Company. Given the data provided at the time this report was prepared, the estimates presented herein are considered reasonable. However, they should be accepted with the understanding that reservoir performance subsequent to the date of the estimates may necessitate revision.

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 determinations, without consideration for other economic criteria, they are not to be construed as an opinion of fair market value.

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

Exclusivity

This report has been prepared for the exclusive use of Indo-Pacific Energy Limited, 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.

	Sproule

October 2003

Introduction — Page 3

Certification

Report Preparation

The report entitled “Evaluation of the Gas and Condensate Reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand (As of October 1, 2003),” was prepared by the following Sproule personnel:


	Intermediate Engineer


	Manager, Geoscience


	Project Leader and Manager, Engineering

	Sproule

October 2003

Introduction — Page 4

Sproule Executive Endorsement

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


	Rudolf Cech, P.Eng. Senior Vice-President, International

Permit to Practice

Sproule International Limited is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and hereby attests to its qualifications by signing this permit to practice stamp.

PERMIT TO PRACTICE
Sproule International Limited

____________________________________________________________
Signature

October 10, 2003
Date

PERMIT NUMBER: P6151
The Association of Professional Engineers,
Geologists and Geophysicists of Alberta

	Sproule

October 2003

Introduction — Page 5

Certificate

Floyd P.R. Williams, B.Eng., P.Eng.

I, Floyd P.R. Williams, Intermediate Engineer at Sproule International Limited, 900, 140 Fourth Ave SW, Calgary, Alberta, declare the following:

1.	I hold the following degree:

	a.	B.Eng., Mechanical Engineering (1996), Lakehead University, Thunder Bay ON, Canada

2.	I am a registered professional:

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

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

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

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

4.	My contribution to the report entitled “Evaluation of the Gas and Condensate Reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand (As of October 1, 2003)” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule International Limited. I did not undertake a field inspection of the properties.

5.	I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Indo-Pacific Energy Limited.

	Sproule

October 2003

Introduction — Page 6

Certificate

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

I, Douglas J. Carsted, Manager, Geoscience, 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.	My contribution to the report entitled “Evaluation of the Gas and Condensate Reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand (As of October 1, 2003)” 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.

5.	I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Indo-Pacific Energy Limited.

	Sproule

October 2003

Introduction — Page 7

Certificate

Greg D. Robinson, B.Sc., P.Eng.

I, Greg D. Robinson, Manager, Engineering at Sproule International Limited, 900, 140 Fourth Ave SW, Calgary, Alberta, declare the following:

1.	I hold the following degree:

	a.	B.Sc. Civil Engineering (1978) University of Manitoba, Winnipeg MB, Canada

2.	I am a registered professional:

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

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

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

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

	c.	Society of Petroleum Engineers (SPE)

4.	My contribution to the report entitled “Evaluation of the Gas and Condensate Reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand (As of October 1, 2003)” is based on my engineering knowledge and the data provided to me by the Company, from public sources, and from the non-confidential files of Sproule International Limited. I did not undertake a field inspection of the properties.

5.	I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Indo-Pacific Energy Limited.

	Sproule

October 2003

Introduction — Page 8

Certificate

Rudolf Cech, M.Sc., P.Eng.

I, Rudolf Cech, Senior Vice-President (International) and Director of Sproule Associates Limited, 900, 140 Fourth Ave SW, Calgary, Alberta, declare the following:

1.	I hold the following degree:

	a.	M.Sc. Mining Engineering (1966) University of Mining Technology, Ostrava, Czechoslovakia

2.	I am a registered professional:

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

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

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

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

	c	Canadian Society of Petroleum Geologists (CSPG)

4.	My contribution to the report entitled “Evaluation of the Gas and Condensate Reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand (As of October 1, 2003)” 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 Associates Limited. I did not undertake a field inspection of the properties.

5.	I have no interest, direct or indirect, nor do I expect to receive any interest, direct or indirect, in the properties described in the above-named report or in the securities of Indo-Pacific Energy Limited.


	Rudolf Cech, P.Eng.

	Sproule

October 2003

Summary — Page 1

SUMMARY

Tables S-1 and S-2 summarize our independent evaluation of the gas and condensate reserves of Indo-Pacific Energy Limited in the Kahili Field of New Zealand, using forecast prices and costs and constant prices and costs, respectively. The effective date of the evaluation is October 1, 2003.

Table S-1
Summary of the Evaluation of the Gas and Condensate Reserves
of Indo-Pacific Energy Limited in the Kahili Field of New Zealand
As of October 1, 2003, U.S. Dollars
Forecast Prices and Costs

	Remaining Reserves^a				Net Present Values ^{a, b}
	Gross	Company Gross	Company Net	At 0% M$	At 10% M$	At15% M$	At 20% M$
Pipeline Gas (MMcf) Proven Undeveloped Probable Total Condensate (MBbls) Proven Undeveloped Probable Total	2,465 1,916 4,382 50.9 39.0 89.9	1,109 862 1,972 22.9 17.5 40.4	1,054 793 1,849 21.8 16.4 38.2	2,284 1,771 4,055 -^c -^c-^c	1,962 1,267 3,229 -^c-^c-^c	1,833 1,096 2,928 -^c-^c-^c	1,720 959 2,679 -^c-^c-^c

Table S-2
Summary of the Evaluation of the Gas and Condensate Reserves
of Indo-Pacific Energy Limited in the Kahili Field of New Zealand
As of October 1, 2003, U.S. Dollars
Constant Prices and Costs

	Remaining Reserves^a			Net Present Values ^{a, b}
	Gross	Company Gross	Company Net	At 0% M$	At 10% M$	At15% M$	At 20% M$
Pipeline Gas (MMcf) Proven Undeveloped Condensate (MMbbl) Proven Undeveloped	2,465 50.9	1,109 22.9	1,054 21.8	2,334 -^c	2,006 -^c	1,874 -^c	1,759 -^c

a.	Values may not add exactly due to rounding
b.	Before income tax.
c.	Values included with gas reserves.

	Sproule

October 2003

Summary — Page 2

The “Gross Remaining Reserves” are the total remaining recoverable reserves associated with the acreage in which the Company has an interest. The “Company Gross Reserves” are the Company’s working interest share of the remaining reserves, before deduction of any royalties. The “Company Net Reserves” are the gross remaining reserves of the properties in which the Company has an interest, less all royalties and interests owned by others.

The net present values presented in Tables S-1 and S-2 are presented in United States dollars and are based on annual projections of net revenue, which were discounted at various rates.

The Kahili Field is located on the onshore portion of the Taranaki Basin which lies along the west coast of the North Island (see Figure S1). The basin, which contains Cretaceous to recent aged sediments, covers an area of some 85,000 km², most of which lies offshore. The Kahili structure is associated with a reverse fault that provides three-way dip closure with the eastern edge of the field sealed along the trust fault.

The Company owns a 45% working interest in Petroleum Exploration Permit (PEP) 38736. The first well, Kahili-1, was drilled in January 2002. The well tested small amounts of oil from the Tariki sandstone reservoir. The well was plugged back and drilled directionally (Kahili-1a) to target the Tariki sandstone at a structurally higher location. Kahili-1a did not encounter the Tariki sandstone, passing through the eastern bounding fault above the reservoir. The well was plugged back and sidetracked to the south as well Kahili-1b, and encountered a gross gas pay column of 28 metres (TVD). The upper 17 metres of the gas column were tested at initial rates of up to 5.9 million cubic feet of gas per day. The initial condensate gas ratio (CGR) was 38 barrels per MMcf, stabilizing to 30 barrels per MMcf.

The reserves assigned were estimated volumetrically. The Company provided five interpreted 2D seismic lines as well as time structure, velocity and depth structure maps for the Kahili structure. An audit of the seismic interpretation was conducted on the data provided, and the depth structure map on the top of the Tariki Sandstone was accepted as being representative of the structure. The volumetric estimates of original gas-in-place and condensate were based on the depth structure map, well log analysis, pressure tests and a PVT study.

The Company has entered into arrangements with NGC Holdings Ltd. (NGC), whereby a pipeline and pre-treatment facilities will link the Kahili gas discovery into NGC’s gas gathering system and the Kapuni gas treatment plant.

NGC will build, own and operate the pipeline and the separation and storage facilities, while the Company will remain responsible for operation of the well. NGC will purchase the gas and LPG’s at the pre-treatment site. The Company will uplift the condensates from that site and transport them to the Omata tank farm near New Plymouth, for export and sale.

	Sproule

October 2003

Summary — Page 3

The development was scheduled to come on stream April 1, 2004. The sole production well, Kahili-1b, was forecast to initially produce at a raw gas rate of 3.5 MMcfd.

The Base Gas Price is $NZ 3.25 per gigajoule. At a current exchange rate of 0.5979 $US per $NZ, and converting to imperial units, the Base Gas Price equates to $US 2.05 per MMBTU. The gas price is escalated annually based on the change in the Producers Price Index SN8 (PPI-SN8), as published by the Department of Statistics. This escalation was forecast at 1.5 percent per year.

The price used for condensate sales was based on Sproule’s forecast for Tapis oil. The Tapis oil price schedule was derived by deducting $US 0.75 per barrel from Sproule’s WTI oil price forecasts.

NGC is to recover funding of the pipeline and treatment facility costs through fees.

Capital and operating cost estimates have been escalated at 1.5 percent per year to the date incurred, in the forecast prices and costs case.

Well abandonment costs have been included in this evaluation. Site restoration costs have not been included.

Income taxes have not been considered in this evaluation. The Company has informed us that they are currently in a non-taxable position.

Forecasts of production and net revenue for the 1P and 2P reserves, using forecast prices and costs, are included as Tables S-3 through S-5. Table S-6 presents forecasts of production and net revenue for the 1P reserves using constant prices and costs.

	Sproule

	Sproule

	Sproule

	Sproule

	Sproule

October 2003

Discussion — Page 1

DISCUSSION

1.0 GENERAL

Sproule has independently evaluated the reserves associated with the Company’s interest in the Kahili Field of New Zealand. Proven and probable gas and condensate reserves were estimated deterministically using volumetric methods.

The Company owns a 45% working interest in Petroleum Exploration Permit (PEP) 38736. The lands included in this permit are shown in Figure 1. The first well, Kahili-1, was drilled in January 2002, testing a thrust faulted structure associated with the Tarata Thrust Zone. The well tested small amounts of oil from the Tariki sandstone reservoir at a depth of -2 687 metres. The well was plugged back and drilled directionally (Kahili-1a) to target the Tariki sandstone at a structurally higher location, 600 metres to the southeast. Kahili-1a did not encounter the Tariki sandstone, passing through the eastern bounding fault above the reservoir. The well was plugged back and sidetracked to the south as well Kahili-1b, encountering a gross gas pay column of 28 metres (TVD). The upper 17 metres of the gas column was tested at initial rates of up to 5.9 million cubic feet of gas per day. The initial condensate gas ratio (CGR) was 38 barrels per MMcf, stabilizing to 30 barrels per MMcf.

2.0 GEOLOGY

2.1 Regional Geology

Figure S1 (located in the Summary section of the report) shows the location of the Kahili structure on the Taranaki peninsula, the onshore portion of the Taranaki Basin which lies along the west coast of the North Island. The basin, which contains Cretaceous to recent aged sediments, covers an area of some 85,000 km², most of which lies offshore. The Kahili structure is situated along the Tarata Thrust Zone to the west of the main north-south trending Taranaki Fault. A number of proven fields are associated with the Tarata Thrust Zone including the proven Tariki and Ahuroa gas condensate fields located just to the south of Kahili (Figure S1). The structure is associated with a reverse fault that provides three-way dip closure with the eastern edge of the field sealed along the trust fault.

Defined by a series of five 2D seismic lines the structure is fairly well constrained. Similar to the Tariki and Ahuroa fields, gas condensate is trapped in Oligocene age sandstone belonging to the Tariki Member of the Otaraoa Formation. The Tariki Member consists of interbedded sandstone and mudstone turbidites, deposited on outer shelf fans. An offsetting well, Tariki North-1a, was cored through the upper 19 metres of the Tariki Member. The sandstones are

	Sproule

October 2003

Discussion — Page 2

described as moderately sorted fine to coarse-grained sediments comprised mostly of quartz with minor amounts of feldspar and lithic fragments. The average porosity and permeability values calculated from the core samples are 13 percent and 18 md respectively. Porosity values ranged from 4.5 percent to 16.6 percent while permeability values ranged from 0.2 to 102 md. The cored interval in Tariki North-1a corresponds to the pay section encountered by the Kahili-1b well.

2.2 Geophysics

The Company provided five interpreted 2D seismic lines as well as time structure, velocity and depth structure maps for the Kahili structure. An audit of the seismic interpretation was conducted on the data provided, with a focus on the final depth structure map. Using the well control from three Kahili wells and the Tariki North-1a well, the depth structure map (Figure 2) was found to be in agreement with the true vertical depth and offset calculated for the top of the Tariki Sandstone from the directional survey data provided. The depth structure map on the top of the Tariki Sandstone was accepted as being representative of the structure and subsequently used in the volumetric estimates of original gas-in-place.

2.3 Petrophysics

The Company provided the digital well data for the original Kahili-1 well in addition to the well data for the two sidetracks, Kahili-1a and Kahili-1b. Well logs and core data for the offsetting directionally drilled Tariki North-1a well were also supplied. The initial Kahili-1 well tested oil and encountered the Tariki sandstone below the gas and condensate bearing section. The first sidetrack, Kahili-1a, was drilled towards the southeast and crossed the east bounding fault prior to intersecting the main reservoir sandstone. The well was plugged back and kicked-off to the southwest as the Kahili-1b sidetrack. This sidetrack intersected the Tariki sandstone at an elevation of -2 472 metres, approximately 53 metres below the mapped crest of the structure.

The Kahili-1b well log analysis results are presented in Figure 3, with the gas-water contact of –2 500 metres indicated in green. The logs are displayed as true vertical depth, correcting for the deviation of the wellbore. The well encountered 28 metres of gross pay above the gas-water contact of –2 500 metres. Using the core data from the Tariki North-1a well, a permeability cutoff of 0.6 md was used to establish a porosity cutoff of 8 percent. Using this cutoff with the log porosity for the Kahili-1b well, the net porous sandstone was determined. Water saturation values were calculated using the Archie equation and values of a, m, n, and Rw of 1, 2, 2 and .077 ohmm respectively. A water saturation cutoff of 45 percent was used to determine net gas pay. Increasing the water saturation cutoff to 50 percent did not have an impact on the net pay determination.

	Sproule

October 2003

Discussion — Page 3

The Tariki North-1a well, located only 200 metres south of the Kahili-1b well, did encounter two metres of gas pay at the top of the Tariki Sandstone. The estimated gas-water contact for this well based on the log analysis is –2 479 metres, 21 metres higher than that encountered by Kahili-1b. Based on this information it has been assumed that the fault that separates the Kahili structure from the closure mapped to the south and tested by the Tariki North-1a well is sealing. The gas volume that would be trapped in the crest of the Tariki North structure has not been included in this evaluation.

The average porosity calculated for the net pay section is 14 percent with an average water saturation of 26 percent. Since the Kahili-1b well intersected the reservoir below the structural crest, a well drilled at the crest should encounter approximately 53 metres of additional gross gas pay. An average reservoir porosity of 12 percent was calculated for this interval using the Kahili-1b well logs. The average water saturation was increased to 30 percent to account for the reduced porosity calculated over the interval. The gas-in-place volume associated with this interval has been included in the probable category.

The average reservoir permeability estimated from the Kahili-1b Production Test # 3 is only 0.6 md and is lower than expected when compared to the average air permeability of 18 md measured on the Tariki North-1a core. Using the petrophysical logs for the Tariki North-1a well and the Timur permeability equation, a log derived average permeability of 14 md was calculated for the cored interval, which is in agreement with the core data. The correlation of the Tariki Sandstone is quite good between the Kahili-1, Kahili-1b and the Tariki North-1a wells. Using the same permeability equation on the Kahili-1b logs, an average permeability of 19 md was calculated for the gas pay interval. This value is closer to the permeability measured on core and much higher than what the production test data suggests.

3.0 ESTIMATION OF RESERVES

3.1 Volumetric Estimates

The areal volumetric assignments for the Kahili gas field were based on the depth structure maps supplied by the Company for the Kahili structure. As mentioned earlier in the Geophysics section of this report (Section 2.2), the depth structure map on the top of the Tariki sandstone was accepted as being representative of the structure, and therefore, subsequently used in the areal estimates of the original gas-in-place.

The reservoir parameters used in the volumetric calculations are presented in Table 1.

The 1P areal volumetric assignment shown in Table 1 was based on the Kahili-1b well, which intersected the Tariki Sandstone reservoir below the structural crest. A well drilled at the crest

	Sproule

October 2003

Discussion — Page 4

should encounter approximately 53 metres of additional gross gas pay. The gas-in-place volume associated with this interval has been included in the probable category.

The average porosity and water saturation used were as discussed in the Petrophysics section of the report. The reservoir pressure was determined from the production tests. The compressibility factor (Z) value of 0.903 came from the PVT study (pg. 12 of 35) performed by Petrolab. This PVT study can be found in Appendix C of this report.

3.2 Material Balance

A conventional P/Z material balance analysis was performed on the Kahili gas field. The plot shown below illustrates this P/Z analysis. An OGIP volume of approximately 3.35 Bcf was extrapolated using well test production and pressure data. This is a reasonable match to the 1P volumetric estimate of 3.648 Bcf. It is recognized that the available data used to perform the material balance estimate is limited, and for this reason, the volumetric estimates were used.

The initial reservoir pressure for the Kahili gas field was noted on Production Test #2 to be 4,484 psia at mid perforations depth of –2 478 mss. The second reservoir pressure point from Production Test #3 was determined to be 4,367 psia after some 58.3 MMscf of gas production. This pressure was based on the Horner extrapolation shown below. An additional 13.5 psi was added to the extrapolated 4,353.5 psia to bring the pressure to mid perforations depth of –2 478 mss.

	Sproule

October 2003

Discussion — Page 5

3.3 Pressure Transient Analysis

Production Test #3 was performed on the Kahili-1b well from April 25, 2003 to May 26, 2003. The test objectives were to obtain and measure a stabilized flow rate of the subject well following re-perforation of the Production Test #2 interval, in conjunction with further perforations from 2 840.5m to 2 845m MD. A second objective was to obtain better surface gas samples, as there was evidence the previous samples taken from Production Test #2 may have underestimated the liquids content of the reservoir gas.

	Sproule

October 2003

Discussion — Page 6

The well was opened for flow at the following choke settings during Production Test #3:

	24/64” choke -	at which 5.9 MMscf/d was observed for 8 hours

	16/64” choke -	at which 3.4 MMscf/d was observed for 18.75 hours

	20/64” choke -	at which 4.5 MMscf/d was observed for 11.5 hours

	28/64” choke -	at which 5.7 MMscf/d was observed for 12 hours

	36/64” choke -	at which 6.0 MMscf/d declining to 4.1 MMscf/d was observed for 136 hours

	and 28/64” choke	(adjusted to sustain 3.5 MMscf/d for 9 hours).

The figure shown below illustrates the test results.

	Sproule

October 2003

Discussion — Page 7

Two sets of separator gas and condensate samples were taken during the 16/64” choke setting, at which 3.4 MMscfd was recorded. These samples were sent to PetroLab for compositional analysis. Appendix C contains the full reservoir fluid analyses and results from that PVT study.

The derivative plot of the Kahili-1b Production Test #3 is shown below.

From the derivative analysis shown above, it can be said that radial flow ended at approximately 110 ft into the reservoir. The calculated permeability (k) is approximately 0.5 millidarcy (md) with an apparent skin of –0.5 during the transient period. The linear ½ slope during the late time period on the derivative analysis is indicative of channel linear flow from which one can conclude that a narrow reservoir may exist. Also, the Horner slope breaks upwards at 4:1 which indicates the presence of two sealing boundaries. This well test interpretation compares well with the Geological and Geophysical results.

	Sproule

October 2003

Discussion — Page 8

4.0 GAS CONTRACT

A 7-mile pipeline will run from the site to NGC’s 24-inch untreated gas pipeline, where a pre-treatment facility will be built to separate and store condensates, before injection of the gas stream into the Kapuni pipeline. The point of sale for gas will be the meter at the treatment facility.

The development was scheduled to come on stream April 1, 2004. The sole production well, Kahili-1b, was forecast to initially produce at a raw gas rate of 3.5 MMcfd.

The term of the contract will be for the life of the Kahili Field. This includes the productive life of the Kahili-1b well and of any future wells.

NGC is to recover funding of the pipeline and treatment facility costs by way of the following fees:

Annual fixed fee	$NZ 500,000 per year	(approx. $US 300,000 per year)
Variable condensate charge	$NZ 3.50 per barrel	(approx. $US 2.10 per barrel)

These fees are escalated in the same manner as the gas price.

	Sproule

October 2003

Discussion — Page 9

5.0 DELIVERABILITY MODELING

Gas well deliverability models, for both the 1P and 2P cases, were constructed using Neotechnology Consultants Limited’s FORGAS software (version 4.513). The gas reservoir, defined volumetrically as presented in Table 1 of this report, was assumed to behave as a tank with uniform pressure throughout. The purpose of the gas well deliverability models was to estimate the deliverability over time and to determine the raw gas volumes that could be recovered based on the surface infrastructure defined in the report entitled, “Indo Pacific/NGC – Kahili 1B Wellhead Development – Option 2: Revised Location of Wellstream Processing Facilities”. This report was prepared in June 2003 for NGC by P & P Engineering Solutions, and is included in Appendix D.

The recombined gas analysis used in these FORGAS models was obtained from the Kahili-1b PVT study prepared by PetroLab (file: I-22070, pg:11 of 35). This PVT study consisted of reservoir fluid analyses performed on two surface samples collected during the production testing of the well. A copy of the PVT study is included in Appendix C of this report. The recombined gas gravity is 0.82, with an average produced Condensate-Gas Ratio (CGR) of 39 bbls/MMscf.

A six-inch surface pipeline was assumed from the Kahili-1b well site to NGC’s wellstream pre-treatment facility, some 11 kilometers away. Surface elevations were not known and not considered in this deliverability modeling. The NGC wellstream pre-treatment facility is to consist of gas/liquids separation equipment, liquids storage, gas compression, metering facilities and other associated equipment.

The ‘conventional back pressure equation’ was used to define the gas well deliverability. The ‘c’ and ‘n’ values were determined from the Kahili-1b Production Test #3. This production test was performed in the Tariki Sandstone gas condensate zone from April 25, 2003 to May 26, 2003.

The results of the FORGAS modeling are presented in the following table:

	OGIP (Bcf) (Input)	Peak Raw Gas Rate (Mscf/d)	Production End Date	Gas Recovery Factor (%)
1P	3.648	3,500	June, 2009	75
2P	6.376	3,500	June, 2013	75

	Sproule

October 2003

Discussion — Page 10

The Kahili-1b 1P and 2P raw gas deliverability rates are shown below:

	Sproule

October 2003

Discussion — Page 11

6.0 PRODUCTION FORECASTS

The sales gas production forecast was determined by applying a varying shrinkage factor to the raw gas rates obtained from the FORGAS deliverability modeling. The gas shrinkage factor used was varied from a maximum of 10% down to a minimum of 6%, for the following reasons:

The Kahili gas field can be described as an under-saturated lean retrograde gas reservoir. With an initial reservoir pressure of 4,484 psia and a dew point pressure of 3,755 psia, a reservoir pressure drop of 729 psi is required before liquids begin dropping out in the reservoir. From the FORGAS modeling results, the dew point pressure is reached in the first 5 months for the 1P case and in the first 8 months for the 2P case. A maximum shrinkage factor was used during this period, as the raw gas would yield the maximum CGR.
Based on the recombined gas analysis from the PVT study (see Appendix C), a calculated shrinkage value due the C5⁺, N₂ and CO₂ was estimated to be 6.1%. With fuel loss, a total maximum shrinkage of 10 percent was used.
As the raw gas production becomes leaner below the dew point pressure, a minimum shrinkage factor (including fuel and condensate recovery) of 6.0 percent was used.

The C5+ production forecasts were derived using the constant-volume-depletion results from the PVT study shown in Appendix C (page 21 of 35). Basically, from saturation pressure of 3,740 psig the CGR was measured on a calculated cumulative recovery during pressure depletion. This resulted in the following CGR and corresponding reservoir pressure table, which was used for the C5+ recovery forecast.

CGR (bbl/MMscf)	Reservoir Pressure (psia)
39	3,740
26	3,350
21	3,000
16	2,600
12	2,200
9	1,800
8	1,400
8	1,000

	Sproule

October 2003

Discussion — Page 12

The following graphs present the 1P and 2P forecasts generated.

	Sproule

October 2003

Discussion — Page 13

7.0 PETROLEUM ROYALTY REGIME

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

The rates are:

AVR: 5 percent of net sales revenue
APR: 20 percent of the accounting profit

The net sales revenue is determined by deducting netbacks from gross sales revenue. Netbacks mean that portion of the sale price that represents the cost of transporting, storing and processing the petroleum between the “Point of Valuation” and the “Point of Sale”. The “Point of Valuation” is defined by the Minister, and will generally be the same as the “Point of Sale”. Netbacks (or net forwards) will generally not be allowed or be significant. In our evaluation we have assumed the “Point of Valuation” to be the same as the “Point of Sale” for gas (pre-treatment facility at Kapuni pipeline). Therefore, netbacks were not deducted in calculating the ad valorem royalty on gas. In the case of condensate, a netback was deducted for costs incurred between the pre-treatment facilities and the Omata tank farm.

The APR is payable on the net accumulated accounting profit of production from a producing field. Accounting profits are the excess of net sales revenue over the total of allowable APR deductions. The allowable APR deductions are production costs, capital costs (exploration, development, permit acquisition and feasibility study costs), indirect costs, abandonment costs, operating and capital overhead allowance, operating losses and capital costs carried forward, and abandonment costs carried back. Past costs for purposes of the calculation of APR are $US 3,723,000 (Company share).

8.0 OPERATING AND CAPITAL COSTS

The following operating and capital costs were scheduled in our evaluation:

Capital Costs:
Site costs in 2004	$US 90,000
Development Costs	paid by NGC
Well Abandonment Costs	$US 30,000

	Sproule

October 2003

Discussion — Page 14

Operating Costs:
NGC Annual Fixed Fee	$US 300,000 per year
NGC Variable Processing Condensate Charge	$US 2.10 per barrel
Fixed Well Costs	$US 2,000 per well month
Condensate Sales and Trucking (price adjustment)	$US 3.55 per barrel

The above costs are in 2004 dollars and were forecast to escalate at 1.5 percent per year to the date incurred.

9.0 PRICING

As described above in the “Gas Contract” section of the report, the Base Gas Price equates to $US 2.05 per MMBTU. The gas price is escalated annually based on the change in the Producers Price Index SN8 (PPI-SN8), as published by the Department of Statistics. This escalation was forecast at 1.5 percent per year. A heating value of 1,226 BTU per scf was used in the revenue calculations.

The price used for condensate sales was based on our forecast for Tapis oil. The Tapis oil price schedule was derived by deducting $US 0.75 per barrel from our WTI oil price forecasts.

Sproule’s short-term outlook for oil prices adopts the NYMEX futures market for the forecast period ending June 30, 2005. The forecast used in this evaluation was derived as of October 1, 2003 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 an October 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.

The NYMEX oil futures prices are the foundation of Sproule’s energy pricing models in the early years. In the long term, the price of oil will be governed by supply and demand, and the degree that OPEC is able to limit supply will be a major determinant in establishing oil prices for the next ten years. The long-term oil price forecast was based on a supply forecast that falls in between a fully competitive market and a market controlled by an effective OPEC production quota system. Price stability that promotes a steady growth in demand is therefore in the best interest of the OPEC nations. Sproule’s long-term forecast has been capped at $22.00 per barrel (2003 dollars) in recognition of the economic hurdle rate of alternative supplies. In the foreseeable future, OPEC must limit the real increase in oil prices in order to limit the development of alternative supplies.

	Sproule

October 2003

Discussion — Page 15

The oil price forecasts set out below are based on a forecast of prices for West Texas Intermediate crude at Cushing, Oklahoma. The price of this marker crude is expected to directly reflect world oil prices over the forecast period. The development of the Tapis price is based on historical differentials between these crudes.

Oil Price Forecasts
($US/BBL)

Year	USA WTI	Tapis
2003 3 mo. 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Thereafter	29.02 26.98 23.95 23.00 23.35 23.70 24.06 24.42 24.78 25.15 25.53 25.91 1.5 %/yr	28.27 26.23 23.20 22.25 22.60 22.95 23.31 23.67 24.03 24.40 24.78 25.16 1.5 %/yr

The net condensate price shown in the economic forecasts also include a deduction of $US 3.55 per barrel for trucking and sales costs incurred between the pre-treatment facility and the Omata tank farm.

In the constant price case, $US 2.05 per MMBTU was used for gas sales and $US 24.83 per barrel was used as the net price for condensate, without escalation. The condensate price was based on an October 1, 2003 WTI price of $US 29.13 per barrel.

10.0 NET PRESENT VALUES

The reserves and net present values are summarized in Tables 1 and 2. The present values are presented in United States dollars and are based on annual projections of net revenue, which were discounted at various rates.

	Sproule

October 2003

Discussion — Page 16

Well abandonment costs have been included in this evaluation. Site restoration costs have not been included. Income taxes have not been considered in this evaluation. The Company has informed us that they are currently in a non-taxable position.

Forecasts of production and net revenue for the 1P and 2P reserves, using forecast prices and costs, are included as Tables 3 through 5. Table 6 presents forecasts of production and net revenue for the 1P reserves using constant prices and costs.

	Sproule


Table 1 Kahili, New Zealand Volumetric Reservoir Data
Gas Reserves
Pool/Location	Drainage Area (ac)	Net Pay (ft)	Porosity (%)	Water Saturation (%)	Reservoir Temp. (°‹ F)	Reservoir Pressure (psia)	Z Factor	Original Gas In Place (MMcf)

Tariki Sandstone
Proven	51	58	14	26	185	4,484	.903	3,648
Probable	31	88	12	30	185	4,484	.903	2,728

	Sproule

APPENDIX A

RESERVES DEFINITIONS

	Sproule

Appendix A — Page 1

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

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 + 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 + probable + possible reserves.

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.

	Sproule

Appendix A — Page 2

5.	Developed Producing Reserves Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

6.	Developed Non-Producing Reserves Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

7.	Undeveloped Reserves Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities, and completion intervals in the pool and their respective development and production status.

8.	Levels of Certainty for Reported Reserves The qualitative certainty levels contained in the definitions in Section 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:

	Sproule

Appendix A — Page 3

	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. Whether deterministic or probabilistic methods are used, evaluators are expressing their professional judgement as to what are reasonable estimates.

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

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

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

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

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

	Sproule

Appendix B— Page 1

APPENDIX B

ABBREVIATIONS, UNITS AND CONVERSION FACTORS

	Sproule

Appendix B— Page 2

Appendix B — Abbreviations, Units and Conversion Factors

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

Abbreviations

AFE	authority for expenditure
AOF	absolute open flow
bopd	barrels of oil per day
bfpd	barrels of fluid per day
BS&W	basic sediment and water
BTU	British thermal unit
bwpd	barrels of water per day
CF	casing flange
CGR	condensate gas ratio
D&A	dry and abandoned
DCQ	daily contract quantity
DSU	drilling spacing unit
DST	drill stem test
EOR	enhanced oil recovery
EPSA	exploration and production sharing agreement
FVF	formation volume factor
GOR	gas-oil ratio
GORR	gross overriding royalty
HCPV	hydrocarbon pore volume
ID	inside diameter
IOR	improved oil recovery
IPR	inflow performance relationship
KB	kelly bushing
LKH	lowest known hydrocarbons
LNG	liquefied natural gas
LPG	liquefied petroleum gas
MPR	maximum permissive rate
MRL	maximum rate limitation
NGL	natural gas liquids
NORR	net overriding royalty
NPI	net profits interest
NPV	net present value
OD	outside diameter

	Sproule

Appendix B— Page 3

OGIP	original gas in place
OOIP	original oil in place
ORRI	overriding royalty interest
P1	proven
P2	probable
P3	possible
P&NG	petroleum and natural gas
PI	productivity index
PPM	parts per million
PSU	production spacing unit
PVT	pressure-volume-temperature
RFT	repeat formation tester
SS	subsea
TVD	true vertical depth
PSA	production sharing agreement
PSC	production sharing contract
WGR	water gas ratio
WI	working interest
WOR	water oil ratio
2D	two-dimensional
3D	three-dimensional
4D	four-dimensional
1P	proven
2P	proven plus probable
3P	proven plus probable plus possible
^oAPI	degrees API (American Petroleum Institute)

	Sproule

Appendix B— Page 4

	Sproule

Appendix B— Page 5

	Sproule

Conversion Tables

Conversion Factors — Metric to Imperial

cubic metres (m³) (@ 15°C)	x 6.29010	= barrels (bbl) (@ 60° F), water
m³(@ 15°C)	x 6.3300	= bbl (@ 60° F), Ethane
m³(@ 15°C)	x 6.30001	= bbl (@ 60° F), Propane
m³(@ 15°C)	x 6.29683	= bbl (@ 60° F), Butanes
m³(@ 15°C)	x 6.29287	= bbl (@ 60° F), oil, Pentanes Plus
m³(@ 101.325 kPaa, 15°C)	x 0.0354937	= thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F)
1,000 cubic metres (10³m³) (@ 101.325 kPaa, 15°C)	x 35.49373	= Mcf (@ 14.65 psia, 60°F)
hectares (ha)	x 2.4710541	= acres
1,000 square metres (10³m²)	x 0.2471054	= acres
10,000 cubic metres (ham)	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 (mPas)	x 1.0	= centipoise

	Sproule

Conversion Tables (Cont'd)

Conversion Factors — Imperial to Metric
barrels (bbl) (@ 60°F)	x 0.15898	= cubic metres (m³) (@ 15°C), water
bbl (@ 60°F)	x 0.15798	= m³(@ 15°C), Ethane
bbl (@ 60°F)	x 0.15873	= m³(@ 15°C), Propane
bbl (@ 60°F)	x 0.15881	= m³(@ 15°C), Butanes
bbl (@ 60°F)	x 0.15891	= m³(@ 15°C), oil, Pentanes Plus
thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F)	x 28.17399	= m³ (@ 101.325 kPaa, 15°C)
Mcf (@ 14.65 psia, 60°F)	x 0.02817399	= 1,000 cubic metres (10³m³) (@ 101.325 kPaa, 15°C)
acres	x 0.4046856	= hectares (ha)
acres	x 4.046856	= 1,000 square metres (10³m²)
acre feet (ac-ft)	x 0.123348	= 10,000 cubic metres (10⁴m³) (ha^.m)
Mcf/ac-ft (@ 14.65 psia, 60°F)	x 22.841028	=10³m³/m³ (@ 101.325 kPaa, 15°C)
Btu	x 1054.615	= joules (J)
British thermal units per standard cubic foot (Btu/Scf) (@ 14.65 psia,	x 0.03743222	= megajoules per cubic metre (MJ/m³) (@ 101.325 kPaa,
60°F)		15°C)
$/Mcf (1,000 Btu gas)	x 0.9482133	= dollars per gigajoule ($/GJ)
$/Mcf (@ 14.65 psia, 60°F) Alta.	x 35.49373	= $/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)

	Sproule

APPENDIX C

PVT STUDY

	Sproule

	Sproule

	Sproule

	Sproule

APPENDIX D

KAHILI 1B FACILITY DEVELOPMENT STUDY

	Sproule

Indo Pacific / NGC – Kahili 1B Wellhead
Development

OPTION 2:

Revised Location of Wellstream Processing Facilities

Report Prepared for:

NGC New Zealand Limited

REPORT NUMBER: 8280-R-002
ISSUE DATE: June 2003

Prepared by:

P&P Engineering Solutions
A division of Plant & Platform Consultants Ltd
PO Box 660, New Plymouth, New Zealand

CONTENTS

			Page No.
1.		SUMMARY	3
2.		INTRODUCTION	4
3.		REFERENCE DOCUMENTS	4
4.		CHANGES TO BASIS OF DESIGN	5
5.		BASIC PROCESS DESCRIPTION	5
6.		DISCUSSION OF CHANGES FROM ORIGINAL CONCEPT	6
	6.1	Site Location for Wellstream Processing	6
	6.2	Processing Equipment	6
	6.3	Raw Gas Pipeline	7
7.		ENGINEERING DESIGN ISSUES AND PROJECT RISKS	9
	7.1	Process	9
	7.2	Site Location / Layout	10
	7.3	Power Supply and Telecommunications	10
	7.4	Water Supply	10
	7.5	Safety Equipment and Site Security	11
8.		COST ESTIMATES	11



APPENDIX


Appendix 1		Revised Cost Estimate Summary
Appendix 2		Revised PFD
Appendix 3		Preliminary Programme
Appendix 4		Preliminary OPEX estimate
Appendix 5		Project Risk Table

Revision Number	*Date*	*Description*	Prepared By	Checked By	Approved By
A B C	05 Jun 2003 12 Jun 2003 19 Jun 2003	Draft Issue for client comment Final Issue Client amendments incorporated (and new composition)	JPW JPW JPW	CRP CRP CRP	WJH WJH WJH

8280-R-002 Rev A June 2003

Summary

Indo-Pacific is the owner and operator of the Kahili gas condensate discovery in north Taranaki. Indo-Pacific is in discussion with NGC concerning NGC’s interest in purchasing the field’s output. NGC might also be prepared to invest in the infrastructure required to bring the wellstream to its “LTS” gas-gathering pipeline.

In March 2003, NGC engaged P&P Engineering Solutions (P&P) to carry out a feasibility study (Report number 8280-R-001 Rev. A) of a gas treatment facility and pipeline between the Kahili 1B well site and the tie-in to NGC’s LTS pipeline. That earlier study is referred to in this report as “Option 1”.

P&P was subsequently requested to investigate an alternative conceptual design. This “Option 2” is described in this report.
The main changes from the previous concept are:

To relocate the gas/liquids separation and gas handling facilities adjacent to the LTS line.
To design the processing equipment for the output of a second well, ie a total gas flow of 10 MMSCFD (11,800 scmh).
New wellfluid composition (increased condensate yield)
To design the pipeline between the well sites and the location of the wellstream processing facilities for transport of the raw wellstream.

Indo-Pacific has also advised that end of life wellhead pressures are projected to decline to approximately 30 barg. The pipeline and separation equipment has been sized to cater for this assuming the wellhead flow drops to 5 MMSCFD. Processing and compression downstream of this has not been considered. The above changes would necessitate an increase in the size of some of the wellstream processing equipment.

This report also includes a revised cost estimate for the proposed works, accurate to within +30% / -10% of expected final costs. As in the previous report, the cost estimate allows for engineering design, procurement, installation, construction and project management activities.

8280-R-002 Rev A

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2	Introduction Indo-Pacific has requested NGC to provide a formal proposal, consisting of conceptual engineering and a cost estimate, for the development of the Kahili Gas Field, located east of Kaimata in Taranaki. The proposal described in this report would involve: Laying a 10 - 12km pipeline to transport the raw wellstream from the Kahili 1B well site to the processing site; and Installing gas/liquids separation equipment, liquids storage, gas compression and metering facilities, and diverse associated equipment and facilities at the processing site; and Injecting the gas into NGC’s 400 NB LTS pipeline via a new Interconnection Point. This study follows on from a previous study by P&P, namely P&P Report number 8280-R-001 Rev. A (“Option 1”). It incorporates the following changes to Option 1: Designing the required pipeline to take the raw wellstream; and Locating the gas/liquids separation and gas handling facilities adjacent to the LTS line; and Re-sizing the pipeline, gas/liquids separation and gas handling facilities for an additional well, ie a gas flow of 10 MMSCFD. New wellfluid composition (increased condensate yield) This report for Option 2 includes a cost estimate for the revised works, accurate to within +30% /-10% of expected final costs. The report also highlights other considerations, engineering issues (such as an expected decline in wellhead pressure to 30 barg at end-of-life) and risks relevant to the outcome of any project.

3.	Reference Documents The following information has been received from NGC and is referenced in the report.

	1.	Email from T. vanGameren, Estimates for Kahili Development - Revised, 01/06/03

	2.	P&P Report number 8280-R-001 Rev. A (Option 1), March 2003

	3.	Email from T. vanGameren, Kahili wellstream composition - Revised, 18/06/03

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Changes to Basis of Design

To allow for the future second well, the design maximum wet gas flow rate has been increased to 10 MMSCFD (11,800 scmh) [Ref. 1].

The wellfluid composition has changed [Ref. 3]. There is a higher yield of condensate in the wellfluid stream.

With the latest wellfluid composition, the original condensate production rate has increased to 350 bbls/day (with vapour recovery).

The following conditions have not changed;

Flowing tubehead pressure:                85-103.4 barg
Flowing tubehead temperature:          32 ^oC
Delivery Pressure to LTS line:            42-45 barg

However, Indo-Pacific predicts that the end of life tubehead pressure will be 30 barg [Ref. 1]

Basic Process Description

Apart from relocation of the site, the arrangement of the processing equipment is more or less the same as in Option1. Refer to Appendix 2 for the Process Flow Diagram (“PFD”).

The original study highlighted the possible requirement for a vapour recovery package to capture vapour from the condensate stock tank and combine it with vapour from the second stage separator. Such a package has been allowed for in assessing space requirements. A separate cost estimate has also been included in Appendix 1.

As noted previously, Indo-Pacific expects that wellhead pressures at end of the field’s life will be approximately 30 barg. The gas/liquids separation and gas handling facilities have been designed to operate at such reduced wellhead pressures.

On the assumption that end of life flow rates from the two wells would be lower than the initial design (< 5 MMSCFD) flows, the pipeline sizing should be adequate notwithstanding the reduced pressure from the field. The processing facility land area and location should be selected to allow for the installation of additional compression, should this be required.

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Discussion of Changes from Original Concept

6.1 Site Location for Wellstream Processing

The LTS pipeline easement adjoins that of the Kapuni – Rotowaro (“200 line”) pipeline. The logical location for a tie-in to the LTS pipeline for Kahili gas is in the vicinity of the Inglewood Offtake Station on the 200 line, located near the intersection of Junction and Suffolk Roads east of Inglewood.

Suitable sites at which to undertake processing of the raw wellstream were identified near the end of the proposed pipeline within one km of the Inglewood Offtake Station. It is possible that the Inglewood Offtake Station site itself could be extended to accommodate the required processing facilities.

The extent of site required is estimated to be approximately 100 x 100 metres in size, ie 1 Hectare. The nearest dwelling would be 150 metres distant from any of the sites identified. All sites are on reasonably flat land. It is recommended that a land area of approximately two hectares be acquired to allow for screen planting and provide for future expansion.

6.2 Processing Equipment

Separator Sizing

The separator equipment sizes have been increased pro-rata to allow for the increased gas flow of 10 MMSCFD (11,800 scmh), ie:

V-001 first stage separator and V-002 second stage separator dimensions have increased. The first stage separator is sized with an allowance for slug volume. Both separators are also sized for the low wellfluid pressure case of 30 barg.
Heater H-001 duty has increased

Condensate Storage Tank Sizing

The Condensate tank capacity has been increased to 1000 barrels to allow for 3 days ullage. Increased condensate rate now requires two road tanker loading trips per day.

For cost estimation purposes, all other equipment has been assumed to be the same size or capacity as before.

Vapour Recovery

A vapour re-compression package has been allowed for and priced as a separate item. Plot space has been allowed for this item.

A preliminary estimate of the duty required is 1000 scmh at a differential pressure of 7 bar.

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6.3 Raw Gas Pipeline

6.3.1 Route

Two routes have been examined. One would be laid within road reserves. The other is a cross-country route. Main line valves have not been allowed for although one might be necessary to protect the Mangonui River from spills.

(i) Road Reserve Route

This route would follow Kohete, Tariki and Tarata Roads, with the length of each section being approximately 4 km, 0.5 km and 8 km respectively. Total pipeline length would be approximately 12.5 km.

Kohete Road has numerous bends and is very narrow. Construction of a pipeline within the road reserve would entail major difficulties and completely disrupt use of the road for a period.

The Tariki Road section is short, although an apparently better option would be to avoid it altogether by crossing a short section of farm land, thereby reducing the pipeline length by several hundred metres.

Tarata Road at its eastern end would involve some problems, associated with bends and narrow verges. Several sections would be very difficult to traverse as there are telecom cables on one side and power poles on the other. Towards the western end of Junction Road the going looks easier. Crossing the major river, the Mangonui, could be achieved by either attaching the pipe to the existing bridge, which appears to be suitable, or by a trenched crossing some two hundred metres upstream where the banks are reasonably low.

The use of road reserves would avoid landowner consenting problems and permit an early start to construction. The disadvantages would be the physical obstacles, the disruption to traffic and the general disturbance to the public during construction.

The estimated pipeline cost using the road reserve route is NZ$2.489 million.

(ii) Cross-Country Route

Total pipeline length would be approximately 10.5km, subject to survey.

The route has not been explored in the field and has been assessed based on general observation of the area from roadsides only. Nevertheless a cross-country route appears to be feasible and potentially offers the advantage of being shorter and less difficult, while minimising disruption to road users and disturbance to the public.

The route would cross numerous small creeks and drains. There would be four road crossings. There would be one major river crossing, the same as the road reserve route. The topography is hilly at the eastern end but flattens out at the western end. Conventional pipelining methods would be practical.

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It would only be necessary to cross the properties of about 6 landowners. Unless it proves too difficult to obtain the consent of all these landowners, the cross-country route would be superior and is therefore recommended.

The estimated pipeline cost using the cross-country route is NZ$2.320 million.

6.3.2 Pipeline Sizing and Rating

A consequence of Option 2 would be that the pipeline rating would have to be increase from Class 600 to Class 900. This arises because, were the shut-off valve at the wellstream processing site to be closed, the pipeline could be exposed to the wells’ shut-in pressure of 123 barg. (See Test #2 Interpretation Report, March 2003). It is not proposed to control the wellstream pressure at the entry to the pipeline. It would be beneficial for sizing the pipeline, and for operation of the wellstream processing facilities (especially the J-T valve) to minimise wellhead choking and operate the pipeline at the highest pressure.

With additional condensate in the wellfluid there is an increased risk of slugging in the pipeline. This is evident from the high pressure drop shown in Table 1 below. At this stage it is considered that a 150 NB pipeline would be large enough and provide a good dispersed flow regime through the line. A 200 NB pipeline has been considered howeverslugging becomes more of an issue with a larger pipeline. This can be evaluated once the pipeline route has been decided and by further simulation work at a later stage.

Pipeline sizing checks are summarized in Table 1 below.

Table 1 – Pipeline Sizing Summary (for 12.5 km length)

Pipeline Size (NB)	Inlet Pressure (barg)	Flow Rate (MMSCFD)	Pressure Drop (bar)	Exit Velocity (m/s)
150	85	10	5.5	1.7
150	30	5	3.4	2.4
200	85	10	1.01	1.0
200	30	5	0.7	1.4

By way of comparison, the velocity threshold at which erosion might become a problem is 11 m/s.

For cost estimation purposes it was assumed that API 5L carbon steel would be a suitable pipe material to use with the raw wellstream. Schedule 40, X52 grade pipe (ie 7.11mm wall thickness) is recommended, in order to provide a 2mm corrosion allowance. External “yellow jacket” polyethylene coating was assumed.

(i) Hydrate Formation

The risk of hydrate formation would be greater with the pipeline flowing the raw wellstream. This wellstream, especially during start-up, may contain condensed water as well as produced water. The quantity of water to be expected from the

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wells during start-up is still unknown. The following measures could be implemented to prevent hydrate formation:

Continuous injection of hydrate inhibitor into the pipeline at each wellsite.
Heating of the pipeline (with steam or electrical tracing)
Injection of a large quantity of hydrate inhibitor into the wellstring prior to start-up, until the well and the underground pipeline have warmed up sufficiently and flow is steady. In addition the pipeline would be insulated where it crosses watercourses.

In the absence of data on expected water quantities, the cost of a methanol injection package has been included in the cost estimate as a separate item. A preliminary estimate of the required duty is :

		Flow rate:	120 l/day (based on Methanol)
		Pump discharge pressure:	123 barg (max)

	Hydrate formation is likely to occur in the first stage separator as well. However this can be addressed by passing a slip stream of hot process gas through heating coils in the liquid compartment of the separator, to melt hydrates. (ii) Potential Slugging in pipeline The pipeline will be carrying 3 phases: hydrocarbon gas, hydrocarbon liquid, and water. Calculations suggest that an “annular flow” regime is likely, and that in light of the expected small liquid flow large slugs are unlikely. Nevertheless, depending on the pipeline route and geometry, small-volume slugs may reach the first stage separator. This could warrant providing additional capacity in the first stage separator, to act as a slug catcher. It is preferred to maintain a 150 NB pipeline as a 200 NB would increase the risk of slugging. It should be noted that the volume of water arising from cooling of the wellstream below its water dewpoint was not considered in calculations to ascertain the likely flow regime.

7.	Engineering Design Issues and Project Risks In conjunction with the Option 1 report [Ref 2], the following sections highlight engineering issues and uncertainties which may have an impact on the project cost/schedule. 7.1 Process

	(i)	In the Option 1 report [Ref 2], the water issue was raised. No further reservoir or other data has been provided to indicate the quantity of free water to be expected during start-up or continuous operation.

	(ii)	As mentioned in section 6.2, injection of hydrate inhibitor would be one way to reduce the risk of hydrate formation in the pipeline. However, should there be

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		significant quantities of free water in the initial wellstream then the flow regime in the pipeline could change and slugging may become an issue, in addition to hydrate formation in the pipeline.

	(iii)	Indo-Pacific has predicted end of life field pressures of approximately 30 barg. Well before then, the gas pressure will be insufficient to either sustain the J-T valve cooling effect, which controls the hydrocarbon and water dew points of the sales gas, or enable that gas to enter the LTS pipeline, without compression. The duty and cost of such compression have not been identified. When the pressure finally declines to 30 barg, liquids will be expected in the gas export line due to high dew points. This has to be clarified by further simulations. It is not known when the wellhead pressure will start to decline, therefore this is also considered a risk to the feasibility of the project.

	(iv)	The increased pressure rating of the pipeline would have a cost impact on the project. There could be savings if the pipeline were rated to Class 600 and protected at the wellhead by high integrity instrument protection shutdown valves and/or pressure safety valves.

	(v)	The latest wellfluid composition contains a higher yield of condensate and therefore, with more liquids present the pressure drop in a 150 NB pipeline is higher. The preferred option is still a 150NB line (providing a 5.5 bar pressure drop is acceptable) as it would provide a more dispersed flow regime with higher liquid velocities. Considering a 200 NB pipeline, increases the potential for larger slug volumes . A cost estimate comparison for a 200 NB pipeline has been included in section 8.0.

	7.2 Site Location / Layout Gas compression due to low end of life field pressures would require extra land. This should be allowed for in the plot area to obtained. It is hoped that the processing facility can be located adjacent to the LTS pipeline. There appears to be sufficient land next to NGC’s Inglewood Offtake Station on the adjacent 200 line. However, there are residential areas about 150m to the south and east of this station. The proposed, and possible future, use of reciprocating compressors would necessitate further work to gain consents for this site, due to noise and emissions. 7.3 Power Supply and Telecommunications There are no additional issues since the original concept. Although located closer to the LTS line, the proposed site will still be un-manned and therefore the telemetry requirements are the same as for Option 1. 7.4 Water Supply There are no additional issues to be addressed over and above the original concept.

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7.5 Safety Equipment and Site Security

There are no additional issues to be addressed over and above the original concept.

Cost Estimates

Cost estimates for Option 2 are included in Appendix 1, “Revised Estimate Summary”.

These estimates are considered accurate to within +30% / -10% of expected final costs. No contingency allowance has been included, except in the case of the pipeline.

At this stage no redundancy has been allowed for and periodic shutdowns will be required for maintenance purposes.

The estimates are based on local industry costs and the present value of the NZ$.

The total estimated cost, based on a 12.5 km cross-country 150 NB pipeline route and including engineering (but not including the vapour recovery package) is NZ$ 5.03 million.

With the increased liquids in the wellfluid a 200 NB pipeline option has been estimated for information. The following table summarizes these costs;

Table 2 – Pipeline Size and route costing summary

Pipeline Diameter (mm NB)	Route Option
Pipeline Diameter (mm NB)	Cross country route	Road route
150	NZ$ 2.32 million	NZ$ 2.49 million
200	NZ$ 2.78 million	NZ$ 3.03 million

A preliminary estimate of operating costs is given in Appendix 4.

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APPENDICES




Appendix 1	Revised Estimate Summary
Appendix 2	Revised Process Flow Diagram
Appendix 3	Preliminary Programme
Appendix 4	Preliminary OPEX estimate
Appendix 5	Project Risk Table

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Appendix 1 – Revised Cost Summary

Tag No	Equipment List
V-001	1^st Stage Separator (3 Phase) Horizontal Class 600 (2100 OD x 6300 S/S)

V-002	2^nd Stage Separator (2 Phase) Vertical Class 150 (1100 OD x 3200 S/S)

H-001	Heater (60kW)

K-001	Compressor (2^ndStage) inlet 7 barg outlet 20 barg 1^ststage
	inlet 20 barg outlet 54 barg 2^ndStage
	( Package Unit )
K-002	Vapour Recovery Unit ( Future Package )

T-001	Condensate tank 1000 bbls API 650

T-002	Produced water tank 30,000 Liter (Polyethylene)

E-001	Wellstream/Gas Exchanger

E-002	Condensate/Gas Exchanger

L-001	Condensate Loadout Arm

P-001	Load Out Pump

PL-001	Launcher

PR-001	Receiver

Equipment

Comments

Cost NZ$

1^stStage Sep ( Horizontal)	Class 600 (Total built up skid)	240,000
2^ndStage Sep. ( Vertical )	Class 150 (Total built up skid)	230,000
Heater ( Water Bath Type )	7 Barg 60kW (Total built up skid)	130,000
Compressor	2 Stage	200,000
Condensate tank	1000 bbls	80,000
Produced Water Tank	30,000 Liter	3,000
Exchanger	Gas to Gas Class 600	20,000
Exchanger	Gas to Gas Class 150	17,000
Load Out Pump	1.5Kw	5,000
Launcher	Class 900 (including 2 valves/endclosure)	30,000
Receiver	Class 900 (including 2 Valves/endclosure)	30,000
		985,000

Utilities

Comments

Cost NZ$

Instrument Air	Skid Package	30,000
O.W system	Includes OW sump & pump	20,000
Potable Water	Small tank (trucked in – 30,000 Liter)	3,000
Telecommunications	To be run from local supply	15,000
Power Supply	To be run from National Grid	30,000
Site lighting	4 Poles/Lights/JB	15,000
Site Earthing	Equipment & Rack	8,000
Utility Water	Pump – Supply from river	10,000
		131,000

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Metering

Comments

Cost NZ$

Custody
Transfer.	To NZ Standards	25,000
Loadout Meter	To NZ Standards (Turbine Meter)	10,000
Gas Analyser		60,000
		95,000

Unloading Area

Comments

Cost NZ$

Condensate loading Arm	Top & Bottom loading (VOPS)	25,000
Sump Tank	Spill drain to Sump tank	8,000
Sump Pump	Pump to System	5,000
Civil/Concrete Pad	Civil & Concrete Pad to load-out area	25,000
Extra Fencing	Fenced Yard area	5,000
Extra Lighting	Lighting to unloading facilities	8,000
		76,000

Telemetry

Comments

Cost NZ$

In Plant	Local to equipment	20,000
Control (in plant)	Overall plant control	20,000
Control (remote)	Remote office control	20,000
Control cabling	Underground or tray support	20,000
		80,000

Structural

Comments

Cost NZ$

Rack	In plant pipe racks	25,000
Supports	Misc. Pipe Supports	10,000
Platforms	Access Platforms	15,000
		50,000

Civil

Comments

Cost NZ$

Earthworks	Say 100m x 100m = 10,000 sq.m @$15/ sq.m	150,000
	(excluding load-out area).
Foundations	Separators (x2)	18,000
	Heater	8,000
	Compressor	15,000
	Condensate Tank	25,000
	Produced Water Tank	1,000
	Potable Water Tank	1,000
	Firewater Tanks (2)	2,000
	Heat Exchangers (x2)	10,000
	AP1 Separator	15,000
	Launcher	4,000
	Receiver	4,000
	Pipe Racks/Supports	10,000
	Bund Walls/paving	40,000
	Fences/Gates	17,000
		320,000

Process Piping

Comments

Cost NZ$

Skids/tanks	Interconnecting piping/insulated if required`	70,000
	Racks piping/insulated if required	40,000
	Misc. Utility piping	20,000
		130,000

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Land Costs

Comments

Cost NZ$

	Land cost for site area 1-2 hectares	100,000
		100,000

Site Facilities

Comments

Cost NZ$

	Building (Small) c/w WC	12,000
	Septic Tank C/w run off	4,000
		16,000

Safety Systems

Comments

Cost NZ$

	ESD (No flare – atmos Vents)	40,000
	Fire Water/Fire Protection -including 2x30,000 liter tanks	50,000
	Safety Shutdown System	20,000
		110,000

TOTAL FOR PLANT DEVELOPMENT (No Contingency added in)

NZ$2,093,000

Feed, Detailed Design and Construction Management

Cost NZ$

Plant Development
Front end engineering design (FEED)	56,550
Detailed Design	226,200
Project Management	94,250
Procurement	37,700
Land Matters	37,700
	452,400

TOTAL FOR PLANT DEVELOPMENT INCLUDING DESIGN

NZ$2,545,400

Additional Equipment

Cost NZ$

Plant Development
Vapour Recovery Unit (VRU)	120,000
	120,000

Additional Equipment

Cost NZ$

Wellsite Development
Wellhead Methanol Injection Package	12,000
	12,000

PIPELINE 150 NB X52 Sch40 –Via Road Reserve

Cost NZ$

Construction	1,325,966
Materials	818,804
Front end engineering design (FEED)	10,000
Detailed Design	79,054
Project Management	111,145
Procurement	5,000
Land Matters	21,225
Contingency	117,810
	2,489,004

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PIPELINE 150 NB X52 Sch40 – Via Cross Country
(Option)

Cost NZ$

Construction	1,118,807
Materials	699,461
Front end engineering design (FEED)	10,000
Detailed Design	89,268
Project Management	111,145
Procurement	5,000
Land Matters	177,068
Contingency	109,787
	2,320,536

Cost NZ$

Total Pipeline 150NB – Via Road Reserve	2,489,004
Total Plant Development including Design – Excludes Vapour Recovery	2,545,400

GRAND TOTAL

NZ$5,034,404

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Appendix 2 – Revised Process Flow Diagram

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Appendix 3 Preliminary Programme

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Table 5	Kahili – 1b, New Zealand, 45% Working Interest, Probable Reserves, As of October 1, 2003, Forecast Prices and Costs, US Dollars

Table 6	Kahili – 1b, New Zealand, 45% Working Interest, Proven Undeveloped As of October 1, 2003, Constant Prices and Costs, US Dollars

Figure 1	Kahili Field Location Map

Figure 2	Top Tariki Sandstone

Figure 3	Kahili – 1b Well Log Analysis

Appendices

Appendix A	Reserves Definitions
Appendix B	Abbreviations, Units and Conversion Factors
Appendix C	PVT Study
Appendix D	Kahibi 1B Facility Development Study