Chelsea Surat Reserves Report 2013

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EVALUATION OF THE OIL RESERVES

AND ASSESMENT OF THE

CONTINGENT AND PROSPECTIVE RESOURCES

OF CHELSEA OIL AND GAS LTD.

IN THE SURAT ASSETS, BOWEN/SURAT BASIN, AUSTRALIA

(As of March 31, 2013)



Copies: Chelsea Oil and Gas Ltd. (5 copies)

Electronic (5 copies)

Sproule (1 copy)

Project No.: 4325.70684

Prepared For: Chelsea Oil and Gas Ltd.

Authors: Barrie F. Jose, P.Geoph., Project Leader

Philip W. Pantella, P.Eng.Suryanarayana Karri, P.Geoph.Alexey Romanov, P.Geo.

Irina Baiseitova, M.Eng.

Vladimir Torres Hernandez, M.Sc.Mustafa Ali Malik, M.Sc.

Exclusivity: This report has been prepared for the exclusive use of Chelsea Oil and GasLtd. It may not be reproduced, distributed, or made available to any othercompany or person, regulatory body, or organization without the knowledge

and written consent of Sproule, and without the complete contents of thereport being made available to that party.



Table of Contents — Page 1

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J:\Chelsea Oil & Gas 70684\Report\Summary.doc

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 Oil Reserves of

Chelsea Oil and Gas Ltd in Queensland, Australia

(As of March 31, 2013) after Income Taxes

Table S-1A Summary of the Evaluation of the Oil Reserves ofChelsea Oil and Gas Ltd in Queensland, Australia

(As of March 31, 2013) before Income Taxes

Table S-1B Summary of the Oil Contingent Resources of



Table S-1C Summary of the Oil Prospective Resources of



Table S-2 Summary of Selected Price Forecasts

(Effective March 31, 2013)




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

Total Probable Plus Possible Reserves

Before and After Income Taxes

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

Probable Undeveloped Reserves


Table S-3B Summary of Oil Reserves and Net Present Values

Total Possible Reserves


Figure S-1 PL 18 and PL 280 (Surat Assets) Location Map

Figure S-2 Daily Company Gross Oil Production Forecast

Figure S-3 Annual Cash Flow (After Income Taxes)

Figure S-4 Net Present Values (After Income Taxes)

Discussion

1. General

2. Geoscience2.1 Regional Geology

2.2 Basin Development and Depositional History

2.3 Reservoir

2.4 Source Rock

3. Geophysics

3.1 Data Control

3.2 Fault Interpretation

3.3 Horizon Interpretation

3.4 Velocity Modeling

4. Petrophysical Evaluation5. Structural Mapping and Rock Volumes

6. Fluid Properties

7. Drill Stem Test

8. Reserves, Contingent and Prospective Resources Assignment

9. Pricing




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10. Operating and Capital Costs

11. Taxes and Royalties

Tables

Table D-1 Volumetric Reservoir Data and Estimates of Oil Technically

Recoverable Volumes of Chelsea Oil Australia PTY Ltd in

Queensland, Australia (As of March 31, 2013)

Table D-1A Volumetric Reservoir Data and Estimates of Contingent

Resources of Chelsea Oil Australia PTY Ltd in Queensland,

Australia (As of March 31, 2013)

Table D-1B Volumetric Reservoir Data and Estimates of Prospective

Resources of Chelsea Oil Australia PTY Ltd in Queensland,

Australia (As of March 31, 2013)

Table D-2 Estimates of Oil Reserves and Net Present Values of


(As of March 31, 2013) before Income Taxes

Table D-3 Summary of Oil Reserves and Net Present Values

Total Probable Plus Possible Reserves


Table D-3A Summary of Oil Reserves and Net Present Values

Probable Undeveloped Reserves


Table D-3B Summary of Oil Reserves and Net Present Values

Total Possible Reserves


References




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Figures

Figure 1 Map of Eastern Australia Showing Locations of the

Bowen and Surat Basins Together with Adjacent Sedimentary

Basins

Figure 2 Location Map Showing the Geographic Distribution of Oil and

Gas in the

Bowen and Surat Basins

Figure 3 PL 18 and PL 280 (Surat Assets) Location Map

Figure 4 Bowen/Surat Basin Stratigraphic Column

Figure 5 Seismic Basemap with Wells, Block Areas and Fault Polygons

Figure 6 Seismic Basemap with Wells and Fault Polygons

Figure 7 Fault Framework from Interpreted Fault Sticks

Figure 8 Time Structure Map of Showgrounds

Figure 9 Depth Structure Map of Showgrounds

Figure 10 Thomby Creek Field - Seismic Line-SD87-4

Figure 11 Thomby Creek Field - Seismic Line-86B-4

Figure 12 Thomby Creek Field – Seismic Line-SD87-17A

Figure 13 McWhirter Field – Seismic Line-86B-24

Figure 14 McGregor Field – Seismic Line-86B-23

Figure 15 McGregor Field – Seismic Line-81B-3

Figure 16 Yellowbank Creek North Field – Seismic Line-85B-5

Figure 17 Yellowbank Creek Field – Seismic Line-78B-29




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Figure 20 Beardmore Field – Seismic Line-81T-21

Figure 21 Beardmore Field – Seismic Line-85-S2

Figure 22 3D Perspective View of Showgrounds Depth Structure Map

Figure 23 3D Perspective View of Base of Showgrounds Depth Structure

Map

Figure 24 Well Thomby Creek 2: Cementation Factor from Core Data

Figure 25 Thomby Creek-1 Well Logs

Figure 26 Top Showgrounds Sandstone Formation Depth Structure Map

Figure 27 Thomby Creek Field Volume Areas Assignment

Figure 28 McWhirter Field Volume Areas Assignment

Figure 29 Yellowbank Creek Field Volume Areas Assignment

Figure 30 Beardmore Field Volume Areas Assignment

Figure 31 Yellowbank Creek North Field Volume Areas Assignment

Figure 32 McGregor Field Volume Areas Assignment

Appendices

Appendix A DefinitionsAppendix B Prices

Appendix C Abbreviations, Units and Conversion Factors



Introduction — Page 1

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Introduction

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

William Petrie, CEO, Chelsea Oil and Gas Ltd (hereinafter referred to as "the Company" or

“Chelsea”). The effective date of this report is March 31, 2013, and it consists of an

evaluation of the hydrocarbon reserves and an assessment of the contingent and prospective

resource volumes associated with the Company’s interests in the Surat Assets (Petroleum

Leases 18 and 280) , located in the Bowen/Surat Basin, State of Queensland, Australia.

This report was prepared in April and May 2013 for the purpose of evaluating the Company’s

oil reserves and estimating the contingent and prospective resource volumes according to the

Canadian Oil and Gas Evaluation Handbook (COGEH) reserves and resources definitions that

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

the Company’s corporate purposes.

This report is contained in one volume, comprising the following sections: Introduction,

Summary, Discussion, National Instrument 51-101, and Appendices. The Introduction

includes the summary of 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 oil reserves,

contingent and prospective resources. The National Instrument 51-101 section presents Form

51-101F2 ― Report on Reserves Data by Independent Qualified Reserves Evaluator or

Auditor, and NI 51-101 formatted tables using Forecast Prices and Costs. Reserves

definitions, product price forecasts, abbreviations, units, and conversion factors are includedin Appendices A, B and C.

Field Operations

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

Sproule. 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, revenue and expense data, product prices actually received, and

other data that were obtained from the Company or from public sources were accepted as




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represented, without any further investigation by Sproule.

2. Property descriptions, details of interests held, and well data, 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.

3. Lessor and overriding royalties and other burdens were obtained from the Company. No

further investigation was undertaken by Sproule.

4. Sproule reserves the right to review all calculations made, referred to or included in this

report and to revise the estimates as a result of erroneous data supplied by the Company

or information that exists but was not made available to us, which becomes known

subsequent to the preparation of this report.

Evaluation Standards

This report has been prepared by Sproule using current geological and engineering

knowledge, techniques and computer software. It has been prepared within the Code of Ethics

of the Association of Professional Engineers and Geoscientists of Alberta (“APEGA”). This

report adheres in all material aspects to the “best practices” recommended in the COGE

Handbook, which are in accordance with principles and definitions established by the Calgary

Chapter of the Society of Petroleum Evaluation Engineers. The COGE Handbook is

incorporated by reference in National Instrument 51-101.

Evaluation Procedures

1. The Company provided Sproule with operating and capital budgets for the fields being

evaluated. In addition, a summary of economic parameters for use in the evaluation was

provided. The economic parameters were independently reviewed by Sproule to ensure

reasonableness.

2. The forecasts of product prices used in this evaluation were based on Sproule’s March 31,

2013 price forecasts. Further discussion is included in Appendix B.

3. Well abandonment and disconnect costs were included in this report at the entity level for

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

made. No provision for abandonment or decommissioning of facilities or pipelines has

been included in this evaluation.




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4. The inclusion of future drilling locations and other future capital investments required a

positive before tax net present value at a 10 percent discount rate.

5.

For this evaluation, Sproule conducted economic analysis using the reserves evaluation

software Merak Peep (Peep). The functionality of the program is not the responsibility of

Sproule, and results were accepted as calculated by the model. Sproule’s responsibility is

limited to the quality of the data input and reasonableness of the outcoming results.

6. Tax pools were provided by the Company and have been included in the Reserves

Evaluation.

7. Contingent and Prospective oil resources were estimated and classified deterministically.

Contingent Resources are discovered and potentially recoverable, but currently sub-

commercial (contingencies may include economic legal, environmental, political and

regulatory matters or lack of market). Prospective Resources are undiscovered and

potentially recoverable.

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, theyshould 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 Sproule’s opinion of fair market value.

3.

The dollar values presented throughout the report are in United States dollars, unlessotherwise stated.

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




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BOE Cautionary Statement

BOEs (or McfGEs or other applicable units of equivalency) may be misleading, particularly if

used in isolation. A BOE conversion ratio of 6 Mcf:1 bbl (or an McfGE conversion ratio of 1

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

burner tip and does not represent a value 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 the future. These statements are based on current

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

results to differ from those anticipated. These risks include, but are not limited to: the

underlying risks of the oil and gas industry (i.e., corporate commitment, regulatory approval,

operational risks in development, exploration and production); potential delays or changes in

plans with respect to exploration or development projects or capital expenditures; the

uncertainty of reserves estimations; the uncertainty of estimates and projections relating to

production; costs and expenses; health, safety and environmental factors; commodity prices;

and exchange rate fluctuation.

Exclusivity

This report has been prepared for the exclusive use of Chelsea Oil and Gas 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, and without the

complete contents of the report being made available to that party.




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Certification

Report Preparation

This report entitled, “Evaluation of the Oil Reserves and Assessment of the Contingent and

Prospective Resources of Chelsea Oil and Gas Ltd. in the Surat Assets, Bowen/Surat Basin,

Australia (As of March 31, 2013)” was prepared by the following Sproule personnel:

_______________________________

Barrie F. Jose, P.Geoph.

Project Leader;

Vice President, Geoscience, International and

Partner

_22_/_05_/2013 dd/mm/yr

_______________________________

Philip W. Pantella, P.Eng.

Manager, Engineering and Partner

_22_/_05_/2013 dd/mm/yr

_______________________________

Suryanarayana Karri, P.Geoph.

Senior Petrophysicist; Supervisor,

Geoscience and Partner

_22_/_05_/2013 dd/mm/yr

_______________________________Alexey Romanov, P.Geo.

Petroleum Geologist and Partner

_22_/_05_/2013 dd/mm/yr

Origina Signe y Barrie F. Jose, P.Geop .

Original Signed by Philip W. Pantella, P.Eng.

Original Signed by Suryanarayana Karri, P.Geoph.

Origina Signe y A exey Romanov, P.Geo.




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_______________________________


Petroleum Evaluator

_22_/_05_/2013 dd/mm/yr

______________________________

Vladimir Torres Hernandez, M.Sc.

Senior Geological Specialist and Associate

_22_/_05_/2013 dd/mm/yr

_______________________________

Mustafa Ali Malik, M.Sc.

Senior Petroleum Geophysical Specialist

_22_/_05_/2013 dd/mm/yr

Sproule Executive Endorsement

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

_______________________________

Greg D. Robinson, P.Eng.

Vice-President, International and Director

_22_/_05_/2013 dd/mm/yr

Permit to Practice

Sproule International Limited is a member of the Association of Professional Engineers and

Geoscientists of Alberta and our permit number is PO6151.

Original Signed by Irina Baiseitova, M.Eng.

Original Signed by Vladimir Torres Hernandez, M.Sc.

Original Signed by Mustafa Ali Malik, M.Sc.

Original Signed by Greg D. Robinson, P.Eng.




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Certificate

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

I, Barrie F. Jose, Vice-President, Geoscience, International and Partner of Sproule, 900, 140

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

1. I hold the following degrees:

a. M.Sc. Geophysics (1979) University of British Columbia, Vancouver, B.C., Canada

b. B.Sc. (Honours) Geological Science with Physics (1977) Queens University, Kingston, ON,

Canada

2. I am a registered professional:

a. Professional Geophysicist (P.Geoph.) Province of Alberta, Canada

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

a. Association of Professional Engineers and Geoscientists of Alberta (APEGA)

b. Canadian Society of Exploration Geophysicists (CSEG)

c. Society of Exploration Geophysicists (SEG)

d. Canadian Society of Petroleum Geologists (CSPG)

e. American Association of Petroleum Geologists (AAPG)

f. Petroleum Exploration Society of Great Britain (PESGB)

g. European Association of Geoscientists and Engineers (EAGE)

h. Indonesian Petroleum Association, Professional Division (IPA)

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

51-101.

5. My contribution to the report entitled “Evaluation of the Oil Reserves and Assessment of

the Contingent and Prospective Resources of Chelsea Oil and Gas Ltd. in the Surat Assets,

Bowen/Surat Basin, Australia (As of March 31, 2013)” is based on my geophysical

knowledge and the data provided to me by the Company, from public sources, and from

the non-confidential files of Sproule. I did not undertake a field inspection of the

properties.

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

Chelsea Oil and Gas Ltd.

Barrie F. Jose, P.Geoph.

Origina Signe y Barrie F. Jose, P.Geop .




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Certificate

Philip W. Pantella, B.Sc., P.Eng.

I, Philip W. Pantella, Manager, Engineering and Partner, of Sproule, 900, 140 Fourth Ave SW,

Calgary, Alberta, declare the following:

1. I hold the following degree:

a. B.Sc. Chemical Engineering (1972), University of Saskatchewan, Saskatoon, Saskatchewan


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



b. Society of Petroleum Engineers (SPE)

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



Bowen/Surat Basin, Australia (As of March 31, 2013)” is based on my engineering


the non-confidential files of Sproule. I did not undertake a field inspection of theproperties.




Philip W. Pantella, P.Eng.

Original Signed by Philip W. Pantella, P.Eng.




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Certificate

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

I, Suryanarayana Karri, Supervisor, Geoscience, Senior Petrophysicist and Partner of Sproule,

900, 140 Fourth Ave SW, Calgary, Alberta, declare the following:


a. M.Sc. Engineering Physics and Instrumentation (1983), Osmania University, Hyderabad, India


a. Professional Geophysicist (P.Geoph.), Province of Alberta, Canada




c. The Society of Petrophysicists and Well Log Analysts (SPWLA)

d. Canadian Well Logging Society (CWLS)


51-101.


the Contingent and Prospective Resources of Chelsea Oil and Gas Ltd. in the Surat Assets,Bowen/Surat Basin, Australia (As of March 31, 2013)” is based on my engineering



properties.




Suryanarayana Karri, P.Geoph.

Origina Signe y Suryanarayana Karri, P.Geo




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Certificate

Alexey Romanov, Ph.D., P.Geo.

I, Alexey Romanov, Petroleum Geologist and Partner of Sproule, 900, 140 Fourth Ave. SW,



a. Ph.D. Eng. (2007), Kazan State Technological University, Kazan, Russia

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

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

Russia


a. Society of Petroleum Engineers (SPE)

b.. Association of Professional Engineers and Geoscientists of Alberta (APEGA)

c. Canadian Society of Petroleum Geologists (GSPG)

3. I am a qualified reserves evaluator as defined in National Instrument 51-101.




knowledge and the data provided to me by the Company, from public sources, and fromthe non-confidential files of Sproule. I did not undertake a field inspection of the

properties.




Alexey Romanov, Ph.D., P.Geo.

Original Signed by Alexey Romanov, P.Geo.




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Certificate


I, Irina Baiseitova, M.Eng., Petroleum Evaluator of Sproule, 900, 140 Fourth Ave. SW,



a. M.Eng. Petroleum Engineering (2012), University of Calgary, Calgary, Alberta, Canada

b. B.Sc. (With Distinction), Petroleum Engineering (2003), Kazakh National Technical University,

Almaty, Kazakhstan






properties.





Original Signed by Irina Baiseitova, M.Eng.




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Certificate

Vladimir Torres, M.Sc.

I, Vladimir Torres, Senior Geological Specialist and Associate of Sproule, 900, 140 Fourth Ave

SW, Calgary, Alberta, declare the following:


a. M.Sc. Geology (1991), Azerbaijan State Oil Academy, Baku, Republic of Azerbaijan

b. M.Sc. Petroleum Geosciences (1997), Institut Francais du Petrole, Paris, France



b. Canadian Society of Petroleum Geologists (CSPG)c. American Association of Petroleum Geologists (AAPG)



Bowen/Surat Basin, Australia (As of March 31, 2013)” is based on my geological



properties.

4. I have no interest, direct or indirect, nor do I expect to receive any interest, direct orindirect, in the properties described in the above-named report or in the securities of


Vladimir Torres, M.Sc.

Original Signed by Vladimir Torres, M.Sc.




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Certificate


I, Mustafa Ali Malik, Senior Petroleum Geophysical Specialist of Sproule, 900, 140 Fourth Ave

SW, Calgary, Alberta, declare the following:


a. M.Sc. Geophysics (1998),Quaid-i-Azam University, Islamabad, Pakistan

b. B.Sc. Physics (1995), University of Punjab, Lahore, Pakistan



b. Society of Exploration Geophysicist (SEG)

c. Canadian Society of Exploration Geophysicist (CSEG)

d. Society of Petroleum Engineers (SPE)

e. European Association of Geoscientists and Engineers (EAGE)



Bowen/Surat Basin, Australia (As of March 31, 2013)” is based on my geophysical



properties.





Original Signed by Mustafa Ali Malik, M.Sc.




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Certificate

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

I, Greg D. Robinson, Vice-President, International and Director of Sproule, 900, 140 Fourth

Ave SW, Calgary, Alberta, declare the following:


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


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




c. Society of Petroleum Evaluation Engineers (SPEE)


51-101.



Bowen/Surat Basin, Australia (As of March 31, 2013)” is based on my engineeringknowledge and the data provided to me by the Company, from public sources, and from


properties.




Greg D. Robinson, P.Eng.

Origina Signe y Greg D. Ro inson, P.Eng.



Summary — Page 1

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Summary

Tables S-1 and S-1A summarize our evaluation of the oil reserves of Chelsea Oil and Gas

Ltd., as of March 31, 2013, after and before Australian income taxes, respectively. Table S-

1B, presents the contingent oil resources of Chelsea Oil and Gas Ltd., as of March 31, 2013.

Prospective Resources of Chelsea Oil and Gas Ltd. are summarized in the Table S-1C. The

Company’s interests are located in the Petroleum Leases 18 and 280 (PL 18 and PL 280),

Bowen/Surat Basin, State of Queensland, Australia. Maps showing the location of the

Company’s Surat Assets are included as Figure S-1 and Figures 1 to 3 (located in the

Discussion section of the report).

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

accordance with Canadian Oil and Gas Evaluation Handbook (COGEH) reserves definitions

and evaluation practices and procedures, which is compliant with Canadian National

Instrument 51-101.

No economic analyses were conducted for contingent and prospective resources.

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. These rates are 5, 10, 15 and 20 percent and undiscounted.

The price forecasts that formed the basis for the revenue projections in the evaluation were

based on Sproule’s March 31, 2013 pricing model. Table S-2 presents a summary ofselected forecasts.

Operating and Capital costs were escalated to the dates incurred at 1.5 percent per year.

Well abandonment and disconnect costs were included in this report at the entity level for

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

made. No provision for abandonment or decommissioning of facilities or pipelines has been

included in this evaluation.

Summary forecasts of production and cash flow for the various reserves categories areincluded as Tables S-3 through S-3B. Figures S-2 through S-4 present the results of our

evaluation in graphical form.



Table S-1

Gross Gross Net At 0% At 5.0% At 10.0% At 15% At 20%

Total Probable 140 140 125 4,470 4,100 3,773 3,484 3,226

Total Possible 261 261 231 5,267 4,593 4,023 3,540 3,129

Total Probable Plus Possible 401 401 356 9,738 8,693 7,796 7,024 6,356

Table S-1A

Gross Gross Net At 0% At 5.0% At 10.0% At 15% At 20%

Total Probable 140 140 125 5,767 5,187 4,692 4,267 3,898

Total Possible 261 261 231 11,608 9,665 8,129 6,900 5,905

Total Probable Plus Possible 401 401 356 17,374 14,852 12,821 11,166 9,803

Values may not add due to rounding.

Company After Income Taxes M$US

Oil (Mbbl)

Escalated Prices and Costs


Remaining Reserves

Chelsea Oil & Gas Ltd.

Block PL 18, Surat Basin, Queensland, Australia

Net Present Values

Chelsea Oil & Gas Ltd.

Block PL 18, Surat Basin, Queensland, Australia

Escalated Prices and Costs

Net Present Values


Remaining Reserves

Company Before Income Taxes M$US

Oil (Mbbl)



(ac) (ft)(%)

(%) RB/STB Mbbls % Mbbls % Mbbls

Showground sandstone

12

2 0

2 3 467 5 23 70 16

34

979 10 98 73 72

* Not adjusted for economic cut-off

average working interest, based on the Company's working interest of 50% in PL 280 and 100% in PL 18

Values may not balance due to rounding

1. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations

using established technology or technology under development, but which are not currently considered to be commercially recoverable due to

one or more contingencies. Contingent resources have an associated chance of development (economic, regulatory, market and facility, corporate

commitment or political risks). These estimates have not been risked for the chance of development. There is no certainty that any portion of

the contingent resources will be developed or, if developed, there is no certainty as to either the timing of such development or whether

it will be commercially viable to produce any portion of the resources.

2. 1C estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed

the 1C estimate.

3. 2C estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be

greater or less than the 2C estimate.

4. 3C estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will

exceed the 3C estimate.

5. The individual field contingent resources volumes were estimated deterministically and the arithmetic summation has been provided. Statistial aggregation has not

been considered.

Oil

FVF

Original Oil

In Place

Technical

RecoveryFactor *

- Cum Production -

Working

Interest**

Company

Technically

RecoverableOil*

Table S-1B

Total of McWhirter and Thomby Creek Fields

Production Licenses 18 and 280, Surat Basin, Queensland, Australia

Volumetric Reservoir Data and Estimates of Contingent Resources (Unrisked)(1,5)

(As of March 31, 2013)Original

Technically

RecoverableOil *

Pool/Location

Drainage

Area Net Pay Porosity

Water

Saturation



(ac) (ft)(%)


Showground sandstone

Low2

2,868 5 149 93 138

Best 34,504 10 441 89 393

High 4

6,884 15 1,064 84 897

* Not adjusted for economic cut-off

** average working interest, based on the Company's working interest of 50% in PL 280 and 100% in PL 18


1. Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered

accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a

chance of development. The reported resources have not been risked for either chance of discovery (geological chance of success) or

chance of development (economic, regulatory, market, facility, corporate commitment, or political risks). There is no certainty tha

any portion of the prospective resources will be discovered and if discovered, there is no certainty as to either the timing of such

development or whether it will be commercially viable to produce any portion of the resources.

2. Low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual

remaining quantities recovered will exceed the low estimate.

3. Best estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual

remaining quantities recovered will be greater or less than the best estimate.

4. High estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual

remaining quantities recovered will exceed the High estimate.

5. The individual field prospective resources volumes were estimated deterministically and the arithmetic summation has been provided. Statistical aggregation

has not been considered. The summation of the unrisked prospect volumes may be misleading because it assumes success for each of the prospect entities.

The chance of this occurring is unlikely.

Original

Technically

RecoverableOil *

Pool/Location

Drainage


Water

Saturation

Oil

FVF

Original Oil

In Place

Working

Interest **

Company

Technically

RecoverableOil*

Table S-1C

Total of Beardmore, McGregor, McWhirter , Thomby Creek and Yellowbank Creek Fields

Production License 18/280, Surat Basin, Queensland, Australia

Volumetric Reservoir Data and Estimates of Prospective Resources (Unrisked)(1,5)


Technical

RecoveryFactor *



Summary

4325.70684.IB.smr


Table S-2

Summary of Selected Price Forecasts

(Effective March 31, 2013)

Year

WTI Cushinga

Oklahoma

($US/bbl)

UK

Brentb

($US/bbl)

Historical

2008 99.59 97.06

2009 61.63 61.53

2010 79.43 79.48

2011 95.00 111.22

2012 94.19 111.44

Forecast

2013 3 mo. Actual 94.35 112.49

2013 9 mo. Estimate 92.85 109.60

2014 90.51 103.84

2015 87.69 99.17

2016 93.22 103.032017 96.96 106.65

2018 98.41 108.25

2019 99.89 109.87

2020 101.38 111.52

2021 102.91 113.20

2022 104.45 114.89

Escalation rate of 1.5% thereafter

Note:

a. 40 degrees API, 0.4% sulphurb. 38 degrees API, 1.0% sulphur c. International Petroleum Exchange British National Balancing Point



3P : <Unnamed Sensitivity>

Economic SummaryBlock PL 18, Surat Basin, Queensland, Australia - Total Probable Plus Possible

Prod'n Start: 2014/01, As Of: March 31, 2013. Escalated Prices and Costs

Company DescriptionNet Revenue Net Expl Net Dev Net Opex

Company (% of Total) 91.38 0.00 100.00 100.00

Company (% of Contr) 100.00 0.00 100.00 100.00

Partner (% of Contr) 0.00 0.00 0.00 0.00

Contr 91.38 0.00 100.00 100.00

NOC 0.00 0.00 0.00 0.00

Model Austral ia Extended PRRT (2012) - 70684

Global Params SIL as of March 31, 2013Escalation Date 2013/01

Discount Date 2013/01

Economic Limit 2020/04

Company Economic IndicatorsDisc. Rate BT NPV AT NPV BT PIR AT P

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

0 17,374 9,738 1.56 0.9

5.0 14,852 8,693 1.49 0.9

10.0 12,821 7,796 1.43 0.9

15.0 11,166 7,024 1.37 0.9

20.0 9,803 6,356 1.32 0.9

25.0 8,669 5,775 1.27 0.9

AT ROR (%) >800.00 Contr Take (%) 46.4

AT Payout (yrs) 1.08 NOC Take (%) 0.0

F&D ($US/BOE) 29.42 Gov't Take (%) 53.5

Company Economics (per Unit)(M$US) (%) ($US/BOE)

Net Revenue 38,667 100.00 108.63

Less:

Bonuses & Fees 0 0.00 0.00

Operating Costs 9,061 23.43 25.45

Tariffs 0 0.00 0.00

Prod & Asset Taxes 0 0.00 0.00

Capital Costs 11,138 28.80 31.29

Plus: Other Income/Expense 0 0.00 0.00

Before Tax Cash Flow 17,374 44.93 48.81

Less Income Tax 7,637 19.75 21.45 After Tax Cash Flow 10,452 27.03 29.36

Company Prod and InvestmentsProject Comp Gross Compan

Oil (MSTB) 401 401

Gas (MMSCF) 0 0

NGL (MSTB) 0 0

Tax (MSTB) - -

Total (MBOE) 401 401

Project Company

Acquisition (M$US) - 0

Exploration (M$US) 0 0

Development (M$US) 10,472 10,472

Abandonment (M$US) 666 666Total (M$US) 11,138 11,138

Economic Summary

Date

CompanySales

Revenue

M$US

SuratOver

RidingRoyalty

M$US

QueenslandRoyalty

M$US

OperatingCosts

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

Cash FlowTotal

M$US

PRRT&

IncomeTax

M$US

After Tax

Cash FlowTotal

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

10,054

13,100

9,217

5,165

2,836

1,593

350

0

42,314

0

263

340

239

133

72

39

8

0

1,094

0

876

1,134

798

444

239

130

27

0

3,647

72

1,634

2,256

1,816

1,307

975

797

203

0

9,061

0

0

0

0

0

0

0

0

0

0

0

5,186

3,740

1,547

0

0

0

0

0

10,472

0

0

0

0

0

0

0

666

0

666

0

0

0

0

0

0

0

0

0

0

-72

2,096

5,629

4,817

3,281

1,550

627

-554

0

17,374

0

0

495

3,318

2,289

1,046

451

38

0

7,637

-72

2,096

5,134

1,500

992

504

176

-592

0

9,738

05/08/20Peep 2010.1

Table S-3




Economic SummaryBlock PL 18, Surat Basin, Queensland, Australia - Probable Undeveloped



Company (% of Total) 91.46 0.00 100.00 100.00

Company (% of Contr) 100.00 0.00 100.00 100.00

Partner (% of Contr) 0.00 0.00 0.00 0.00

Contr 91.46 0.00 100.00 100.00

NOC 0.00 0.00 0.00 0.00







0 5,767 4,470 1.48 1.1

5.0 5,187 4,100 1.43 1.1

10.0 4,692 3,773 1.39 1.1

15.0 4,267 3,484 1.35 1.1

20.0 3,898 3,226 1.31 1.1

25.0 3,576 2,997 1.27 1.0

AT ROR (%) >800.00 Contr Take (%) 57.2




Net Revenue 13,467 100.00 108.07

Less:



Tariffs 0 0.00 0.00


Capital Costs 3,897 28.93 31.27





Oil (MSTB) 140 140

Gas (MMSCF) 0 0

NGL (MSTB) 0 0

Tax (MSTB) - -


Project Company





Economic Summary

Date

CompanySales

Revenue

M$US

SuratOver

RidingRoyalty

M$US

QueenslandRoyalty

M$US

OperatingCosts

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

Cash FlowTotal

M$US

PRRT&

IncomeTax

M$US

After Tax

Cash FlowTotal

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

Total

0

8,570

3,962

1,697

497

0

0

14,725

0

224

101

42

11

0

0

377

0

745

336

139

38

0

0

1,258

72

1,443

943

658

312

0

0

3,427

0

0

0

0

0

0

0

0

0

3,684

0

0

0

0

0

3,684

0

0

0

0

212

0

0

212

0

0

0

0

0

0

0

0

-72

2,474

2,582

859

-77

0

0

5,767

0

0

709

461

126

0

0

1,296

-72

2,474

1,873

397

-202

0

0

4,470

05/08/20Peep 2010.1

Table S-3A



PS : <Unnamed Sensitivity>

Economic SummaryBlock PL 18, Surat Basin, Queensland, Australia - Total Possible



Company (% of Total) 91.34 0.00 100.00 100.00

Company (% of Contr) 100.00 0.00 100.00 100.00

Partner (% of Contr) 0.00 0.00 0.00 0.00

Contr 91.34 0.00 100.00 100.00

NOC 0.00 0.00 0.00 0.00







0 11,608 5,267 1.60 0.8

5.0 9,665 4,593 1.53 0.8

10.0 8,129 4,023 1.46 0.8

15.0 6,900 3,540 1.39 0.8

20.0 5,905 3,129 1.33 0.7

25.0 5,093 2,778 1.27 0.7

AT ROR (%) >800.00 Contr Take (%) 40.9




Net Revenue 25,200 100.00 108.93

Less:



Tariffs 0 0.00 0.00


Capital Costs 7,241 28.73 31.30





Oil (MSTB) 261 261

Gas (MMSCF) 0 0

NGL (MSTB) 0 0

Tax (MSTB) - -


Project Company





Economic Summary

Date

CompanySales

Revenue

M$US

SuratOver

RidingRoyalty

M$US

QueenslandRoyalty

M$US

OperatingCosts

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

Cash FlowTotal

M$US

PRRT&

IncomeTax

M$US

After Tax

Cash FlowTotal

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

1,484

9,138

7,520

4,668

2,836

1,593

350

0

27,589

0

39

239

198

122

72

39

8

0

717

0

131

798

659

406

239

130

27

0

2,389

0

190

1,314

1,159

996

975

797

203

0

5,634

0

0

0

0

0

0

0

0

0

0

0

1,501

3,740

1,547

0

0

0

0

0

6,787

0

0

0

0

-212

0

0

666

0

454

0

0

0

0

0

0

0

0

0

0

0

-378

3,047

3,958

3,357

1,550

627

-554

0

11,608

0

0

-214

2,856

2,163

1,046

451

38

0

6,341

0

-378

3,260

1,102

1,194

504

176

-592

0

5,267

05/08/20Peep 2010.1

Table S-3B



70684

PL 18 and PL280 (Surat Assets) Location Map

http://w



Figure S-2

70684

MCWHIRTER, THOMBY CREEK, YELLOWBANK CREEK NORTHDAILY COMPANY PRODUCTION FORECAST

GROSS OIL



Figure S-3

70684

MCWHIRTER, THOMBY CREEK, YELLOWBANK CREEK NORTH

ANNUAL CASH FLOW (AFTER INCOME TAX)



Figure S-4

70684

MCWHIRTER, THOMBY CREEK, YELLOWBANK CREEK NORTH

NET PRESENT VALUE (AFTER INCOME TAX)



Discussion – Page 1

4325.70684.IB

J:\Chelsea Oil and Gas\Report\Chelsea Summary.doc

Discussion

1. General

Petroleum Leases 18 and 280 (PL 18 and PL 280) are located approximately seven

kilometres south of the Silver Springs Gas field complex on the western flank of the Surat

Basin in southeastern Queensland, Australia. The oilfields in these leases were discovered

by Bridge Oil and later acquired by Brisbane Petroleum and Delbaere Associates in June

1993. The oil in all fields is accumulated in the Triassic Showgrounds Sandstones (Figure 4).

PL 18 with an area of 186 square kilometers contains the Thomby Creek Oil Field, McGregor

Field, Yellowbank Creek Field and Yellowbank Creek North Field.

PL 280 with an area of 91 square kilometers contains the Beardmore Field.

The McWhirter Field straddles the boundary between PL 18 and PL 280.

The Thomby Creek Oil field was discovered by Bridge oil in 1979 with 5 producing wells

being drilled to April 1981. These 5 wells produced 51.5 Mbbls of oil to May 1986 when the

field was suspended. Thomby Creek-5 well was put back on production in 1999 and shut-in

at the end of 2009. The cumulative oil production from the field was 58.6 Mbbls to March

31, 2013.

The Yellowbank Creek Oil Field was discovered by the Yellowbank Creek-2 well in 1982. Twomore wells, YBC-3 and YBC-4, were drilled in 1982. All three wells were shut in

(Yellowbank-2 in December 1993, Yellowbank-3 in March 2010, Yellowbank-4 in April 2006)

due to excessive water cut and they have remained shut-in. The cumulative oil production

from the three wells was 425 Mbbls.

Within the McWhirter Area (located in both PL 18 and PL 280), the McWhirter East-1 well

was drilled in November 1978 but only completed for production in December 1997. This

well produced 49.9 Mbbls to 2006. The McWhirter-1 discovery well had been plugged and

abandoned by Crusader in 1993, after producing 2,038 bbls. Two more dry holes were

drilled in the area (McWhirter-2 and Abbott-1).

The YBCN-1 well located in the Yellowbank Creek North area was drilled in August 1987 but

only completed for production in June 1993, producing 32.9 Mbbls until it was shut-in in

April 2004 due to high water cut.




4325.70684.IB.smr


Three wells were drilled within the Beardmore Area (Beardmore-1, Beardmore-2 and

Beardmore Southwest-1A). The Beardmore-1 well was drilled in 1981 and three DSTs were

conducted. Mud cut oil was recovered at surface from the Showgrounds sandstone and the

Kuttung Formation. The Beardmore-2 well was drilled in 1987 and a DST flowed gas to

surface at a small rate. Several barrels of condensate/oil cut mud were retrieved during

circulation. Well Beardmore-SW 1A was drilled in 1982. Only mud was recovered during a

test of the Showgrounds sandstone formation.

The Company owns a 100-percent interest in Petroleum Lease 18 and a 50 percent interest

in Petroleum Lease 280. The remaining interests in the Petroleum Lease 280 are held by

Longreach Oil Ltd.

2. Geoscience

2.1 Regional Geology

The Bowen Basin was formed during the earliest Permian to Late Triassic time. It is a

narrow, elongate north–south trending basin, recognized as the northern element of the

Bowen-Gunnedah-Sydney basin system (Figure 1), with a length of 900 km extending from

Collinsville in Queensland to Moree in New South Wales. It covers a total area of just over

200,000 km2. The rocks in the Bowen Basin consist of Early Permian marine sediments, Late

Permian coal measures, Early Triassic red beds, and Middle Triassic terrigenous sediments

(Fielding et al. 1990).

The Bowen Basin consists of two main depocentres, the Taroom and Denison troughs

(Figure 1). The north-trending Taroom Trough is the largest and most easterly, containing

up to 9000 m of Permian and Triassic sediments and covers an area of approximately

50,000 km2 (Hawkins et al. 1992). It is bounded to the west by the Wunger Ridge, Roma

and Collinsville shelves and the Comet Ridge. Its eastern limit is the structural eastern

margin of the basin. To the west and separated from the Taroom Trough by the Comet

Ridge, the north-northwest trending Denison Trough is 320 km long and 60 km wide. It is

bounded on the west by the Nebine Ridge and Springsure Shelf and on the north and south

by the Capella and Roma Shelves, respectively.

The distribution of discovered oil and gas within the Bowen and Surat Basins is shown in

Figure 2. A more local map of the well and seismic control in the vicinity of PL 280 and PL

18 is provided in Figure 3.




4325.70684.IB.smr


2.2 Basin Development and Depositional History

The stratigraphic sequence in the Bowen Basin is summarized in Figure 4. Various tectonic

models have been put forward to explain the origin of the Bowen Basin, usually involving

Permian extension and Triassic compression. In the compressional phase, extensional faults

were reversed and extensive erosion took place with up to 3,000–4,000 m of section lost

from some parts of the basin.

The evolution of the Bowen Basin commenced in the Late Carboniferous or Early Permian

through an initial rift formed by back-arc extension, followed by a mid-Permian sag phase

and then to a Late Permian-Middle Triassic foreland basin stage. Uplift, thrusting, and a

more fluvial environment existed in the Triassic with red bed deposition of the Rewan

Group. Reservoir sands are developed locally within the Rewan Group in the Taroom Trough

but are of poor quality.

Uplift in the west resulted in the alluvial quartzose deposits of the Clematis Group around

the Early-Middle Triassic boundary. The fluvial system of the Clematis Group extended over

the Denison Trough and into the Taroom Trough where it is represented along the

southwest margin by the principal petroleum reservoir, the Showgrounds Sandstone. This is

the primary reservoir target within the Company’s PL 18 and PL 280 leases. This succession

in the Taroom Trough is significantly thinner in the southern part of the trough than in its

maximum development in the north. A basin transgression in the south and west portions of

the Taroom Trough halted fluvial deposition and a widespread seal of the fine-grained

sediments of the Snake Creek Mudstone Member of the lower Moolayember Formation were

deposited. A return to dominantly alluvial systems in the Middle Triassic saw the depositionof the youngest Bowen Basin sequence, the upper Moolayember Formation. Up to 5,000 m

of Triassic sediments are preserved in the northern Taroom Trough.

2.3 Reservoir

The rocks in the Bowen Basin consist of Early Permian marine sediments, Late Permian coal

measures, Early Triassic red beds, and Middle Triassic terrigenous sediments (Fielding et al.

1990).

The Showgrounds Sandstone is the primary reservoir in the PL 18 and PL 280. The averageporosity is 16% and water saturation is approximately 44%. Permeability varies from 5 md

over the Yellowbank Creek North area to 300 md in the Yellowbank Creek area. The

Showgrounds Sandstone reservoir at Thomby Creek Field has an average permeability of 30

md.




4325.70684.IB.smr


2.4 Source Rock

In the Denison Trough (Figure 1), gas-prone Type III source rocks of considerable potential

exist throughout the Permian succession with the marine Cattle Creek Formation and the

alluvial coal-bearing Reids Dome Beds constituting the most favorable source facies

(Jackson et al. 1980, Baker et al. 1991). The Taroom Trough and the Surat Basin can be

classified as a more oil-prone region than the Denison Trough, based on known discoveries

(Figure 2).

Hawkins et al. (1992) have concluded that the entire Permian to Triassic succession of the

Taroom Trough is dominated by Type III kerogen.

The Blackwater Group, particularly along the eastern and southern margins, contains

significant amounts of oil-prone kerogen while restricted source potential also exists in the

Back Creek Group (Figure 4).

Thomas et al. (1982) have interpreted the Blackwater Group to be within the oil window

throughout much of the Taroom Trough, whereas the Back Creek Group is overmature for

gas over much of the northern part of the Taroom Trough.

3. Geophysics

3.1 Data Control

Seismic control for PL 18 and PL 280 is through a 2D seismic grid of various vintages and

line spacing. In total 37 seismic lines were shot in these two blocks and seismic data is of

fair to good quality. Some mistie problems between different vintages were observed and

minimized prior to the horizon interpretation. In total, 30 wells, including dry holes, have

been drilled in the two blocks and production has been obtained from five oilfields. Most

wells were drilled either on or in close proximity to the 2D seismic control. The Company

has provided all the data related to 2D seismic, time horizons, well locations, well logs,

formation tops, and production profile data. Figure 5 and 6 show the base map with wells,

2D seismic and the interpreted fault polygons.

3.2 Fault Interpretation

A map and 3D perspective view of the fault framework developed by Sproule is shown in

Figure 7. The Showgrounds interval may be compartmentalized by these faults, and they

play a role in establishing areal extent of the fields and the associated reserves volumes.




4325.70684.IB.smr


3.3 Horizon Interpretation

Due to the complexity of the area and presence of complex faults system, Sproule refined

the horizon picks provided by the Company for the Evergreen, Showgrounds and Basement

horizons. Sproule used these horizon interpretations for the velocity model and depth

conversion. Figures 8 and 9 show the time and depth structure maps of the Showgrounds

reservoir respectively.

Thomby Creek Field:

Figure 10 shows a strike line SD87-4, which passes through the wells Thomby Creek-3 and

Thomby Creek-5. The Thomby Creek Field is a subtle four-way dip anticlinal structure

transected by some local NNW-SSE trending faults. There are six wells drilled in the Thomby

Creek Field, of which five lie in the Company’s PL 18. The field is compartmentalized by

these faults, which affect the reservoir and its capacity to produce. Figure 10 shows three

interpreted horizons; Evergreen, Showgrounds Sandstone and Basement on east-west dip

profile SD87-4.

Figure 11 shows a north-south strike profile 86B-4 (NNE-SSW). This line passes through

the well Thomby Creek-6A.

Figure 12 provides another north-south strike profile SD87-17A over the crest of the field

passing through the Thomby Creek-6/6A, –2 and -1 wells.

McWhirter Field:

Figure 13 shows a NW-SE seismic line 86B-24 which passes through the McWhirter-1 well.

The seismic line shows the three interpreted horizons; Evergreen, Showgrounds and

Basement. The McWhirter structure is transected by a major north-south fault, indicated by

a light green fault on the seismic section.

McGregor Field:

Figure 14 shows the seismic line 86B-23 in the NW-SE direction. This lines passes through

the wells McGregor-1, Yellowbank Creek North-1 and Yellowbank Creek-1. The McGregor

Field is bounded by two SSW-NNE trending faults to the east and west of the McGregor-1

well. Figure 15 also shows a dip line 81B-3 in west-east direction across the McGregor Field

and north flank of the Yellowbank Creek North Field.




4325.70684.IB.smr


Yellowbank Creek North Field:

Figure 16 shows a seismic line 85B-5, which passes through the well Yellowbank Creek

North-1. The field is a structural high, bounded by two north-south faults, as shown by a

white ellipsoid in Figure 16.

Yellowbank Creek Field:

Figure 17 shows the seismic line 78B-29 (E-W direction) passing through the Yellowbank

Creek-1 well, which was a dry hole and did not produce. The well was drilled very close to

the fault in a structurally low position.

Figure 18 shows the seismic line 85B-6 in west-east direction. This line passes through the

Yellowbank Creek-3 well, which was a producing well near the northern apex of the fault

block.

Two more producing oil wells, Yellowbank Creek-2 and Yellowbank Creek-4, were drilled and

the seismic line 81B-2 passes through these wells as shown in Figure 19. The structural high

is bounded by faults on all but the south side, and the two wells are drilled in two adjacent

fault blocks.

Beardmore Field:

Figure 20 shows seismic line 81T-21, which passes through the wells Beardmore-1 and

Beardmore-2. Beardmore-1 appears to have been drilled near the fault.

The Beardmore Southwest-1A well lies south of the seismic line 85-S2 (Figure 21). The field

is a four way dip structure which is bisected by a fault which runs through the middle of the

field. The fault lies to the east of the Beardmore 2 and Beardmore Southwest 1A wells.

3.4 Velocity Modeling

The horizon interpretation was mainly focused on the reservoir level marker, which is the

Showgrounds Sandstone. A velocity model was created from the available well tops in the

two blocks and the time structure surface, and used in the time to depth conversion.

A 3D perspective view of the Showgrounds Sandstone depth structure map is shown in

Figure 22, which honours the well tops. A Showgrounds-Base depth structure map was

created by an isochore, as shown in 3D perspective view in Figure 23.




4325.70684.IB.smr


4. Petrophysical Evaluation

Sproule conducted a petrophysical analysis of the Showgrounds Formation in Thomby

Creek, Beardmore, McGregor, McWhirter, Yellowbank Creek and Yellowbank Creek North

Fields. The objective of the analysis was to estimate the porosity and water saturation for

the wells having open-hole log data to estimate the original hydrocarbon in place.

The main challenge was to gather the digital data of the wells. The Company supplied open

hole well log data in digital LAS files. However, the data interval did not include the

Showgrounds Formation which is the main target reservoir. Paper copies of the well logs

were either provided by the Company or downloaded from the government website covering

the Showgrounds Formation.

Log data from nineteen wells were analyzed manually, targeting the Showgrounds

Formation. For the majority of wells, the density log was used to calculate the total porosity

and where the density logs were not available the porosity was estimated from the sonic

log.

Since the Showgrounds Formation is mainly composed of sandstone, the matrix density was

set as 2.65 gm/cc and a value of 55 usec/foot was used as the sonic matrix travel time.

The Density porosity equation is:

Where: φe is the porosity from density log; ρb is the measured bulk density in gm/cc, ρma is

the matrix density in gm/cc and ρfl is the fluid density in gm/cc.

The Sonic porosity equation is:

Where: φe is the porosity; ∆Τ is the measured sonic travel time in usec/foot, ∆Τma is the

matrix travel time in usec/foot and ∆Τfl is the fluid travel time in usec/foot.

)(

)(

flma

bma

e ρ ρ

ρ ρ

φ −

−

=

)(

)(

ma fl

mae

DT DT

DT DT

−

−=φ




4325.70684.IB.smr


The water saturation was estimated by using the Archie Equation, assuming the formation

to be clean (having low shale volume).

The values of a, m and n were respectively 1, 1.56 and 1.7. These values are supported by

core data from the Thomby Creek-2 well. An FRF-PHI cross plot was constructed and the

best fit gave a value of m=1.56 (Figure 24). The Rw of the Showgrounds Formation was

found to be between 0.49 ohmm and 0.577 ohmm at the reservoir temperature.

The following table summarizes the average reservoir parameters for the Showgrounds

Formation in the analyzed wells.

Average Reservoir Parameters for Showgrounds Sandstone Formation.

SNo

Well NameTopMD

BaseMD

Pay Average Rw

Feet Feet FeetRt

(OHMM)PHI

(V/V)Sw

(Archie)OHMM

1 Thomby Creek-1 6080 6110 30 55 0.097 0.530 0.49

2 Thomby Creek-2 6090 6119 29 40 0.115 0.546 0.49

3 Thomby Creek-3 6135 6152 17 19 0.164 0.612 0.49

4 Thomby Creek-4 6077 6084 7 29 0.133 0.577 0.49

5 Thomby Creek-5 6050 6085 35 70 0.109 0.412 0.496 Thomby Creek-6A 6099 6134 34 47 0.090 0.622 0.49

7 McGregor-1 6083 6096 13 100 0.109 0.384 0.62

8 Yellowbank Creek-1 6109 6122 13 30 0.127 0.646 0.572




12 Yellowbank Creek North-1 6114 6117 3 22 0.170 0.598 0.577

13 Beardmore SW-1A 5991 5996 5 50 0.061 0.949 0.577

14 Beardmore-1 6080 6095 15 20 0.230 0.478 0.577

15 Beardmore-2 6007 6014 7 45 0.162 0.410 0.57716 McWhirter East -1 6047 6056 10 55 0.197 0.304 0.577

17 McWhirter -1 6049 6055 7 70 0.152 0.336 0.577

18 McWhirter -2 6086 6096 10 8 0.152 1.000 0.577

19 Hollow Tree-1 5919 5923 4 25 0.160 0.586 0.577

n

m

Rt

aRwSw

/1

=

φ




4325.70684.IB.smr


Figure 25 shows an example of the open hole log data across the Showgrounds Formation in

the Thomby Creek-1 well.

5. Structural Mapping and Rock Volumes

A single reservoir level (Showgrounds Sandstone) was mapped at this time. The reservoir

formation tops provided by the Company were reviewed and edited where necessary, and

used to control the top Showgrounds Formation depth structural map during the time to

depth conversion workflow. The top Showgrounds depth structure map is shown in Figure

26.

Isochores for the pay interval within the Showgrounds sandstone were calculated and used

to develop a base net reservoir structural map.

The rock volume between the top and the base reservoir surfaces and down to an oil water

contact, ODT or spill point level depth depending on the field or area, were used to

calculate the net rock volume (NRV). The STOOIP for the Showgrounds sandstone net

reservoir interval was calculated for each field by fault block and reserves or resources

category (Figures 27-31). A summary is shown in the following table.




4325.70684.IB.smr


Fields Volumes Categorization

Field or Area Category Block CaseFluid Level

type

Depth Area GRV

m TVDSS acres acre ft

Thomby Creek

Reserve

A Possible

OWC -1588

70 1,160

BProbable 36 1,156

Possible 25 800

CProbable 14 393

Possible 25 824

D2C 14 334

3C 28 786

ProspectiveResource

Low 68 2,333

Best 128 4,300

High 221 5,392

McWhirter North

Reserve EastP10 Spill -1585 164 1,244

P90 ODT -1580 116 819

Reserve WestP10 Spill -1585 159 901

P90 ODT -1580 129 761

McWhirter South ProspectiveResource

High Spill -1585 220 1,431

Low ODT -1580 154 1,000

Yellowbank Creek

ReserveP10 Spill -1590 174 2,653

P90 ODT -1586.5 148 2,132

ProspectiveResource

High Spill -1590 82 1,199

Low ODT -1586.5 63 904

Yellowbank Creek North Reserve 3P OWC -1573 35 263.6

BeardmoreProspectiveResource

High Spill -1590 384 3,706

Low ODT -1579 131.8 761

6. Fluid Properties

Yellowbank Creek Field

Two surface fluid samples from wells Yellowbank Creek 3 and Yellowbank Creek 4 were

obtained during drillstem tests. API oil gravities of 53.5 and 45.5 degree were reported for

the Yellowbank Creek 3 and Yellowbank Creek 4 wells.

Yellowbank Creek North Field

One surface fluid sample from the Yellowbank Creek North 1 well was analyzed. An API oil

gravity of 55.3 degree was reported for this oil sample.




4325.70684.IB.smr


Thomby Creek Field

The API gravity was obtained for surface samples of the reservoir fluid produced from the

Thomby Creek 2 and Thomby Creek 5 wells. The reported API oil gravity was variable in the

range of 49-50 degrees.

McWhirter Field

Laboratory PVT analyses were conducted on a downhole reservoir fluid sample from the

McWhirter 1 well. The results are summarized in the following table:

McWhirter Oil Properties

Well McWhirter 1

Oil density at standard conditions 52.5 deg API

Reservoir temperature 180 deg F

Initial reservoir pressure 2,200 psia

Initial formation volume factor 1.303 rb/stb

Oil viscosity at initial reservoir conditions 0.416 cp

Initial solution gas-oil ratio 357 scf/bbl

Saturation pressure 415 psia

Oil viscosity at saturation pressure 0.352 cp

Beardmore Field

An API oil gravity of 51.32 degrees was determined for a surface oil sample from the

Beardmore 2 well.

Considering the limited availability of complete reservoir fluid properties data, reservoir fluid

parameters typical for PL 18 area were used for the evaluation. These parameters are

presented in the following table:

Beardmore Oil Properties

Oil density at standard conditions 53.5 deg API

Reservoir temperature 170 deg F

Initial reservoir pressure 2,697 psia

Initial formation volume factor 1.323 rb/stb

Oil viscosity at initial reservoir conditions 0.428 cp

Initial solution gas-oil ratio 357 scf/bbl

Saturation pressure 652

psia




4325.70684.IB.smr


7. Drill Stem Tests


Well Yellowbank Creek 2 tested 49 degree API oil at a rate of 1,536 barrels per day from the

Showgrounds zone (1,831-1,836.7 m) in April 1982.

Well Yellowbank Creek 3 tested oil at a rate of 509 barrels per day with a reported GOR of

200 ft3 /bbl from the Showgrounds zone (1,845-1,855 m) in August 1982 at a surface

flowing pressure of 181 psia.

DST 1 was conducted in the well Yellowbank Creek 4 over the Showgrounds interval 1,838-

1,888 m. KB. Only mud was recovered from the drill pipe when the DST tool was pulled. The

results of DST 1 were explained by mechanical problems with the packer. DST 2 was

conducted in the well Yellowbank Creek 4 over the interval of 1,825-1,888 m KB. Oil, water

and gas were recovered from the drill pipe but the well did not flow naturally.

Yellow Bank Creek North Field

The Showgrounds Sandstone (1,859.2-1,870 mKB) was tested in the well Yellowbank Creek

North 1 on August 5, 1987. No fluid was produced to surface. However, 10.8 bbls of oil and

15.2 bbls of water were recovered by reverse circulation. Pre-flow pressure data was used

in pressure analyses. The results of pressure transient analyses were provided by the

Company and are summarized in the following table:

Yellowbank Creek North 1 Buildup Analysis

Reservoir Pressure, psia 1,532.4

Permeability, mD 827

Apparent skin 60

The measured reservoir pressure of 1,532.4 psia was much lower than hydrostatic pressure

and the apparent pressure depletion of the reservoir was attributed to fluid production from

nearby fields.

Thomby Creek Field

Three DSTs were conducted in the Thomby Creek 1 well. During DST 1, the well tested oil

from the interval of 1,851-1,861 m. at 468 psia flowing pressure. The associated oil rate

was not reported. During DSTs 2 and 3, only water was tested from the deeper intervals of

1,861-1,863 m and 1,871-1,912 m.




4325.70684.IB.smr


The Thomby Creek 2 well tested oil at the rate of 360 barrels per day from the interval of

1,856-1,868 m with an unstabilized flowing pressure of 180 psia.

The Thomby Creek 3 well tested only water from the interval of 1,866-1,877 m and the well

was abandoned.

During the DST conducted on the Thomby Creek 4 well, only gas was produced to the

surface at a rate too small to measure from the interval of 1,848-1,871 m. Some oil was

recovered during reverse circulation.

The Thomby Creek 5 well tested oil at a rate of 440 barrels per day from the interval of

1,845-1,856 m.

Three DSTs were run in the well Thomby Creek 6A, but only small amounts of mud were

recovered.

McWhirter Field

The McWhirter 1 well tested oil at a rate of 150 barrels per day from the interval of 1,837 to

1,847 m (Showgrounds Sandstone) at a flowing pressure of 410 psia increasing to 1,392

psia. The duration of the flow period was 89 minutes.

The Showgrounds sandstone was tested in the McWhirter East 1 well over the interval of

1,840-1,849.3 m. During the test, gas to surface was observed and 40 bbls of oil wasrecovered.

Beardmore Field

Three DSTs were run in the well Beardmore 1. Mud cut oil and water were recovered at

surface during DST-1 (1,850.1-1,858.4 m). Water and mud were recovered from DST’s 2

and 3.

During DST-1, across the interval of 1,828-1,835.5 m, conducted in the Beardmore 2 well,

only gas produced to the surface at a rate too small to measure. Some oil cut mud wasrecovered during reverse circulation. Only mud with traces of oil was recovered from the

tested interval of 1,827-1,840 m. (DST 2).

Drilling mud was recovered at the surface during the test of the Showgrounds (1,825.4-

1,836.1 m) in the well Beardmore Southwest 1.




4325.70684.IB.smr


McGregor Field

Two DSTs were run in the well McGregor 1.

During DST-1, across the interval of 1,851.5-1,861.5 m of the McGregor 1 well, some gas

flowed to the surface, but no volume was reported. A bottom hole sample recovered from

the well consisted of 12 gallons of water and 5 gallons of oil.

For DST-2, across the interval 1,850.6-1,856.1 m, no gas to surface was reported and drill

pipe recovery was reported to be 103 m of water-cut mud.

The results of pressure transient analyses were provided by the Company and are

summarized in the following table:

McGregor 1 Buildup Analysis

DST-1 DST-2

Reservoir Pressure, psia 1,626 1,609

Permeability, mD 3 2-4

Apparent skin 9 12

The measured reservoir pressure of 1,626 psia was much lower than expected and the

reservoir pressure depletion was explained by the limited area of the pool.

8. Reserves, Contingent and Prospective Resources Assignment

The original oil in place associated with the oil reserves and contingent and prospective

resources were estimated volumetrically, as described in the preceding Section 5: Structural

Mapping and Rock Volumes. Reservoir rock and fluid property data were obtained from core

analyses, well logs and PVT data. Recovery factors were selected after reviewing the

performance of existing wells and by comparing the reservoir under study with published

information on analogous reservoirs that have more firmly established recovery factors from

extended production histories.

Table 1 presents the volumetric parameters used in the calculation of the volumes initially in

place and technically recoverable volumes (before the economic cut off). Summary TablesS-1 and S-1A present summaries of the reserves assigned to McWhirter, Thomby Creek and

Yellowbank Creek North fields after economic cut off with the before and after tax net

present values, respectively, for each reserves category.




4325.70684.IB.smr


Economics have not been run on the contingent and prospective resources with the volumes

reported as being technically recoverable.

Thomby Creek Field

Probable and Probable plus Possible reserves as well as contingent and prospective

resources were assigned to the Showgrounds Sandstone Formation. Probable plus Possible

Reserves were initially assigned to the areas of blocks B and C. Later, under economic

analysis, it was found that the Probable technically recoverable volume assigned in block C

was not sufficient to support the cost of the proposed well and as a result, only Possible

reserves could be assigned. Possible reserves were also assigned to the area of block A.

Contingent 2C and 3C resources were assigned to the area of block D. Prospective

Resources were assigned to the southern portion of blocks C and D. The areal extent for the

assigned reserves and resources is shown in Figure 27.

A recovery factor of 10 percent was assigned for the reserves in blocks A and C and a

higher recovery factor of 20 percent was assigned for the reserves in block B in recognition

of the historic performance of the Thomby Creek-1 and -5 wells.

Recovery factors of 5 and 10 percent were assigned for 2C and 3C contingent resources

respectively. No 1C resources were assigned because of the current uncertainty with respect

to these resources.

Recovery factors of 2, 10 and 20 percent were assigned to the low, best and high

prospective resources cases, respectively. These recovery factors were interpreted from theperformance of existing wells. No reserves or resources were assigned to the previously

drilled wells because it was interpreted from production statistics that these reservoir

volumes had been depleted.

The cumulative oil production of the Thomby Creek field (wells 1, 2, 4 and 5) was 58.64

Mbbl to March 31, 2013. All wells have been shut–in since 2009.

McWhirter Field

Probable and Probable plus Possible reserves were assigned to the east area of theMcWhirter Field. No Contingent 1C resources were recognized because of the current

uncertainty with respect to these resources; but Contingent 2C and 3C resources were

assigned to the northern portion of the structure west of the fault and Prospective

Resources were assigned to the southern portion. The areal extent for the assigned reserves

and resources is shown in Figure 28.




4325.70684.IB.smr


A recovery factor of 25 percent was estimated for both Probable and Probable plus Possible

Reserves based on the performance of the McWhirter East 1 well.

The drilling of one vertical well was included in the probable area. Drilling of two vertical

wells was specified for the probable plus possible reserves category. An initial oil production

rate of 150 bpd was used in the forecast. Due to the absence of production history data

from the McWhirter Field, the estimate of the initial rate was based on the DST results from

the McWhirter 1 well.

Recovery factors of 5 and 10 percent were assigned to the 2C and 3C Contingent resources

cases, respectively, and again, no 1C Contingent resources were recognized because of

current uncertainties. Recovery factors of 2, 5 and 10 percent were assigned to the low,

best and high prospective resources cases, respectively. The assigned recovery factors for

the contingent and prospective resources were influenced by the performance of the

McWhirter 1 well. Total oil production from the McWhirter Field (wells 1 and East 1) was 52

Mbbl to 2006.


Prospective resources were assigned to the Showgrounds Sandstone Formation. Recovery

factors of 20, 30 and 40 percent were assigned for the low, best and high estimates,

respectively. These recovery factors were estimated based on the performance of the

currently shut in wells Yellowbank Creek 2, Yellowbank Creek 3 and Yellowbank Creek 4.

The areal extent for prospective resources is shown in Figure 29.

No reserves were assigned to the existing wells because it was interpreted from production

statistics that these reservoir volumes had been depleted, all production having ceased in

March 2010. The cumulative field oil production (wells 2, 3, and 4) was 425 Mbbls.

Yellow Bank Creek North Field

Proved (1P), Proved plus Probable (2P), and Proved plus Probable plus Possible (3P)

technically recoverable volumes were initially assigned to the Showgrounds Sandstone

Formation with recovery factors of 30%, 40% and 50%, respectively. Under economicanalysis it was found that the technically recoverable volumes assigned at the 1P and 2P

certainty levels were not economic to develop with a new well and, accordingly, only

Possible reserves could be assigned. The areal extent for reserves is shown in Figure 31.




4325.70684.IB.smr


The cumulative oil production from the Yellowbank Creek North-1 well was 32.9 Mbbl and

the well has been shut-in since 2004 due to high water cut.

The drilling of one vertical well was specified for the reserves evaluation. An initial oil

production rate of 40 bpd, estimated based on Yellowbank Creek North 1 well production

data, was used in our forecast for the possible case.

Beardmore Field


factors of 2, 5 and 10 percent were assigned for the low, best and high resources cases,

respectively. These recovery factors were estimated with consideration for the test results

of the Beardmore-1, Beardmore-2 and Beardmore-SW1 wells. The areal extent for the

assigned resources is shown in Figure 30.

McGregor Field


factors of 2, 5 and 10 percent were assigned for the low, best and high resources cases,

respectively. The areal extent for the assigned resources is shown in Figure 32.

9. Pricing

Sproule’s oil price forecast in effect on March 31, 2013 for Brent crude formed the basis forthe prices used in our evaluation of the Surat area oil reserves.

A negative price offset of 2.5 US$/bbl was applied to the Brent crude oil price forecast.

Transportation costs were included in the operating costs.




4325.70684.IB.smr


10. Operating and Capital Costs

The Company provided estimates of investments and expenses required to develop and

operate the Thomby Creek, McWhirter and Yellowbank Creek North fields.

Costs of US$ 1.479 million and US$ 2.151 million were provided by the Company for drilling

and completing vertical and horizontal wells, respectively. The capital costs for developing

of Thomby Creek, McWhirter and Yellowbank Creek North fields are summarized in the

following table.

Gross Capital Expenditures, M$US(2013 Terms)

2P 3P

2014 2014 2015 2016

Drilling of 1 horizontal well in ThombyCreek Field (Block B)

2,151 2,151

Drilling of 1 horizontal well in ThombyCreek Field (Block C)

2,151

Drilling of 1 vertical well in Thomby CreekField (Block A)

1,479

Drilling of one vertical well in YellowbankCreek North Field

1,479 1,479

Drilling of one vertical well in McWhirterField (probable area)

1,479 1,479

Drilling of one vertical well in McWhirterField (possible area)

1,479

Total 5,109 5,109 3,630 1,479

Abandonment cost* 300 600

*Well abandonment and disconnect at cessation of production.




4325.70684.IB.smr


The operating costs for Thomby Creek, McWhirter and Yellowbank Creek North fields are

summarized in the following table.

Operating Expenditures

(2013 Terms)

Cost Unit

Transportation cost $US/bbl 7

Administrative Cost M$US/yr 72

Insurance Cost M$US/yr 75

Petroleum Tenure Rent Cost M$US/yr 23

Power M$US/yr 50

Chemicals M$US/yr 10

Lubricants M$US/yr 10

Storage M$US/yr 75

Well interventions were scheduled at costs of US$ 105 thousand (vertical well) and US$ 120

thousand (horizontal well) per two years for each well.

Export tariffs were estimated at US$ 5.5 per barrel of oil.

Well abandonment and disconnect costs of $US 100 thousand per well were used. No

allowances for reclamation or salvage values were made.

Prices and costs were escalated at 1.5 percent annually.

11. Taxes and Royalties

Corporate income tax is applied at a rate of 30%. The Company has advised that their

outstanding tax loss carry forward, as of March 31, 2013, was AUD 1.65 million. AQueensland royalty of 10% and an over-riding royalty of 3% are applied to the value of

production after deducting costs associated with processing and transportation. Petroleum

Resource Rent Tax (PRRT) is applied to the taxable revenue at a rate of 40% after

applicable deductions that include the 10% Queensland royalty. A historical cost pool for

PRRT purposes of AUD 9.2 million has also been applied.



(ac) (ft)(%)

(%) RB/STB Mbbls % Mbbls Mbbls Mbbls


Shut-in Wells: YBC-2, YBC-3, YBC-4 425 - -

Thomby Creek Field

Shut-in Wells: TC-1, TC-2, TC-5 57- -

Block A

Possible Undeveloped 70 17 11 50 1.323 373 10 37 37 37

Block B

Probable Undeveloped 36 32 11 50 1.323 372 20 74 74 74

Probable plus Possible Undeveloped 61 32 11 50 1.323 629 20 126 126 126

Block C


Total Thomby Creek Blocks A,B and C

Shut-in Wells: TC-1, TC-2, TC-5 57 -

Probable Undeveloped 372 20 74 74 74

Probable plus Possible Undeveloped 1,393 15 202 202 202

McWhirter Field ( East Area)

Proved (Shut-in well: McWhirter East 1 ) 50 - -

Probable Undeveloped 80 9 17 32 1.323 476 25 119 69 69

Probable plus Possible Undeveloped 170 7 17 32 1.323 867 25 217 167 167

Yellowbank Creek North Field

Shut-in Well: YBCN-1 33 -


TOTAL (Arithmetic)

Probable Undeveloped 848 23 193 143 143

Possible Undeveloped 1,547 19 294 261 261

Probable plus Possible Undeveloped 2,395 20 487 404 404

* Not adjusted for economic cut-off Values may not balance due to rounding

- Cumulative Production -





Gross Remaining

Technically

Recoverable Oil *

Company Remaining

Technically

Recoverable Oil *

Table D-1McWhirter, Thomby Creek and Yellowbank Creek North Fields

Production License 18, Surat Basin, Queensland, AustraliaVolumetric Reservoir Data and Estimates of Technically Recoverable Volumes


Pool/Location

Gross Original

Technically

Recoverable Oil

*

Technical

Recovery

Factor *

Original Oil

In Place

Oil

FVF

Drainage

Area

Water

Sat'nPorosityNet Pay



(ac) (ft)(%)


Thomby Creek Field

Block D

1C2

0 0

2C3

14 24 11 50 1.323 107 5 5 100 5

3C4

42 27 11 50 1.323 360 10 36 100 36

McWhirter Field (West Area)

2 -

2C3 80 7 17 32 1.323 360 5 18 62 11

3C4

165 6 17 32 1.323 619 10 62 58 36

TOTAL (Arithmetic)5

2 -

2C3 467 5 23 70 16

3C4 979 10 98 73 72

Not adjusted for economic cut-off



1. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations

using established technology or technology under development, but which are not currently considered to be commercially recoverable due to

one or more contingencies. Contingent resources have an associated chance of development (economic, regulatory, market and facility, corporate

commitment or political risks). These estimates have not been risked for the chance of development. There is no certainty that any portion of

the contingent resources will be developed or, if developed, there is no certainty as to either the timing of such development or whether

it will be commercially viable to produce any portion of the resources.

2. 1C estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed

the 1C estimate.

3. 2C estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be

greater or less than the 2C estimate.

4. 3C estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will

exceed the 3C estimate.

5. The individual field contingent resources volumes were estimated deterministically and the arithmetic summation has been provided. Statistial aggregation has not

been considered.


Oil

FVF

Original Oil

In Place

Technical

RecoveryFactor *

1C (Shut-in Well: McWhirter 1)2

1C (Shut-in Wells)2

Gross Original

Technically

Recoverable Oil*

Working

Interest **

Company

Remaining

TechnicallyRecoverable Oil *

Table D-1A

McWhirter and Thomby Creek Fields


Volumetric Reservoir Data and Estimates of Contingent Resources (Unrisked)(1,5)


Pool/Location

Drainage


Water

Sat'n



(ac) (ft)(%)


Beardmore Field (East Area)

Low 2132 6 21 46 1.323 511 2 10 50 5

Best 3225 8 21 46 1.323 1,128 5 56 50 28

High 4

384 10 21 46 1.323 2,491 10 249 50 125

McGregor Field

Low2 146 7 11 38 1.323 397 2 8 100 8

Best3

166 8 11 38 1.323 536 5 27 100 27

High 4333 8 11 38 1.323 1,010 10 101 100 101

McWhirter Field (West Area)

Low 2155 7 17 32 1.323 700 2 14 56 8

Best3

182 7 17 32 1.323 872 5 44 56 24

High 4

220 6.5 17 32 1.323 974 10 9756

54

Thomby Creek Field

Low2

68 34 11 50 1.323 750 2 15 100 15

Best 3128 34 11 50 1.323 1,382 10 138 100 138

High 4221 24 11 50 1.323 1,733 20 347 100 347


Low2

63 14 16 38 1.323 510 20 102 100 102

Best3

72 15 16 38 1.323 586 30 176 100 176

High 4

82 15 16 38 1.323 676 40 270 100 270

TOTAL (Arithmetic)5

Low 22,868 5 149 93 138

Best3

4,504 10 441 89 393

High 4

6,884 15 1,064 84 897

Not adjusted for economic cut-off



1. Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered

accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a

chance of development. The reported resources have not been risked for either chance of discovery (geological chance of success) or

chance of development (economic, regulatory, market, facility, corporate commitment, or political risks). There is no certainty that

any portion of the prospective resources will be discovered and if discovered, there is no certainty as to either the timing of such

development or whether it will be commercially viable to produce any portion of the resources.

2. Low estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual

remaining quantities recovered will exceed the low estimate.

3. Best estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual

remaining quantities recovered will be greater or less than the best estimate.

4. High estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual

remaining quantities recovered will exceed the High estimate.

5. The individual field prospective resources volumes were estimated deterministically and the arithmetic summation has been provided. Statistical aggregation

has not been considered. The summation of the unrisked prospect volumes may be misleading because it assumes success for each of the prospect entities.

The chance of this occurring is unlikely.

Oil

FVF

Original Oil

In Place

Technical

RecoveryFactor *

Gross Original

Technically

Recoverable Oil*

Working

Interest **

Company

Remaining

TechnicallyRecoverable Oil *

Table D-1B

Beardmore, McGregor, McWhirter, Thomby Creek and Yellowbank Creek Fields


Volumetric Reservoir Data and Estimates of Prospective Resources (Unrisked)(1,5)


Pool/Location

Drainage


Water

Sat'n



(Mbbls) (%) (Mbbls) (Mbbls) (Mbbls) (%) (Mbbls) (Mbbls) 0%

Probable Undeveloped 848 22 190 50 140 100 140 125 5,767 5

Possible Undeveloped 1,547 19 294 33 261 100 261 231 11,608 9

Probable plus Possible Undeveloped 2,395 20 484 83 401 100 401 356 17,374 1

Notes:

* adjusted for economic cut-off


Technically Recoverable Volumes

Category

Original

Oil In Place

Recovery

Factor*

Original

Recoverable

Oil *

Cumulative

Production

to

March 31,

2013

Working

Interest

Table D-2Total of McWhirter, Thomby Creek and Yellowbank Creek North Fields

Production License 18, Surat Basin, Queensland, Australia

Reserves and Net Present Values

As of March 31, 2013

Working

Interest

Gross

Oil

Volumes*

Working

Interest

Net

Oil

Volumes*

Gross

Remaining Oil

Volumes*




Economic SummaryBlock PL 18, Surat Basin, Queensland, Australia - Total Probable Plus Possible



Company (% of Total) 91.38 0.00 100.00 100.00

Company (% of Contr) 100.00 0.00 100.00 100.00

Partner (% of Contr) 0.00 0.00 0.00 0.00

Contr 91.38 0.00 100.00 100.00

NOC 0.00 0.00 0.00 0.00







0 17,374 9,738 1.56 0.9

5.0 14,852 8,693 1.49 0.9

10.0 12,821 7,796 1.43 0.9

15.0 11,166 7,024 1.37 0.9

20.0 9,803 6,356 1.32 0.9

25.0 8,669 5,775 1.27 0.9

AT ROR (%) >800.00 Contr Take (%) 46.4




Net Revenue 38,667 100.00 108.63

Less:



Tariffs 0 0.00 0.00


Capital Costs 11,138 28.80 31.29





Oil (MSTB) 401 401

Gas (MMSCF) 0 0

NGL (MSTB) 0 0

Tax (MSTB) - -


Project Company





Economic Summary

Date

CompanySales

Revenue

M$US

SuratOver

RidingRoyalty

M$US

QueenslandRoyalty

M$US

OperatingCosts

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

Cash FlowTotal

M$US

PRRT&

IncomeTax

M$US

After Tax

Cash FlowTotal

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

10,054

13,100

9,217

5,165

2,836

1,593

350

0

42,314

0

263

340

239

133

72

39

8

0

1,094

0

876

1,134

798

444

239

130

27

0

3,647

72

1,634

2,256

1,816

1,307

975

797

203

0

9,061

0

0

0

0

0

0

0

0

0

0

0

5,186

3,740

1,547

0

0

0

0

0

10,472

0

0

0

0

0

0

0

666

0

666

0

0

0

0

0

0

0

0

0

0

-72

2,096

5,629

4,817

3,281

1,550

627

-554

0

17,374

0

0

495

3,318

2,289

1,046

451

38

0

7,637

-72

2,096

5,134

1,500

992

504

176

-592

0

9,738

05/08/20Peep 2010.1

Table D-3




Production DetailBlock PL 18, Surat Basin, Queensland, Australia - Total Probable Plus Possible


production detail 1

Date# of Oil

Wells

ProjectOil

Rate

Bbl/d

ProjOil

Volume

MSTB

CompanyGross

OilVolume

MSTB

CompanyNetOil

Volume

MSTB

OilPrice

$US/Bbl

# of GasWells

ProjectGasRate

mcf/d

ProjectGas

Volume

MMSCF

CompanyGross

GasVolume

MMSCF

CompanyNet

GasVolume

MMSCF $US/M2013(12)

2014(12)

2015(12)2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0.0

2.0

4.86.0

5.9

5.0

4.4

4.0

0.0

---

0

259

353239

130

70

39

25

0

---

0

95

12987

47

26

14

3

0

401

0

95

12987

47

26

14

3

0

401

0

84

11478

42

23

13

3

0

356

112.10

106.34

101.67105.53

109.15

110.75

112.37

114.02

0.00

---

0.0

0.0

0.00.0

0.0

0.0

0.0

0.0

0.0

---

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

Production Details 2

Date

ProjectNGLRate

Bbl/d

ProjectNGL

Volume

MSTB

CompanyGross

NGLVolume

MSTB

CompanyNet

NGLVolume

MSTB

NGLPrice

$US/Bbl

ProjectBOERate

Bbl/d

ProjectBOE

Volume

MBOE

CompanyGross

BOEVolume

MBOE

CompanyNet

BOEVolume

MBOE

TotalProject

SalesRevenue

M$US

TotalCompany

SalesRevenue

M$US

B

$2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

0

0

0

0

0

0

0

0

---

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

---

0

259

353

239

130

70

39

25

0

---

0

95

129

87

47

26

14

3

0

401

0

95

129

87

47

26

14

3

0

401

0

84

114

78

42

23

13

3

0

356

0

10,054

13,100

9,217

5,165

2,836

1,593

350

0

42,314

0

10,054

13,100

9,217

5,165

2,836

1,593

350

0

42,314

05/08/20Peep 2010.1

Table D-3




Revenue & Burden DetailBlock PL 18, Surat Basin, Queensland, Australia - Total Probable Plus Possible


Revenue and Burden Detail All values are company interest unless specified otherwise

DateOil

Revenue

M$US

GasRevenue

M$US

NGLRevenue

M$US

TotalSales

Revenue

M$US

Fixed

M$US

VariableOil

M$US

Well Oil

M$US

VariableGas

M$US

WellGas

M$US

Processing

M$US

OilTransport

M$US2013(12)

2014(12)

2015(12)2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

10,054

13,1009,217

5,165

2,836

1,593

350

0

42,314

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

10,054

13,1009,217

5,165

2,836

1,593

350

0

42,314

72

338

499575

579

528

500

125

0

3,216

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

96

9899

101

102

104

35

0

636

0

1,200

1,6591,142

628

345

194

43

0

5,209

Revenue and Burden Detail 2

Date

SuratOver

RidingRoyalties

M$US

QueenslandRoyalty

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

CashFlow

M$US

PRRT

M$US

IncomeTax

M$US

After Tax

CashFlow

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

263

340

239

133

72

39

8

0

1,094

0

876

1,134

798

444

239

130

27

0

3,647

0

0

0

0

0

0

0

0

0

0

0

5,186

3,740

1,547

0

0

0

0

0

10,472

0

0

0

0

0

0

0

666

0

666

0

0

0

0

0

0

0

0

0

0

-72

2,096

5,629

4,817

3,281

1,550

627

-554

0

17,374

0

0

0

1,647

1,366

649

266

38

0

3,965

0

0

495

1,670

923

397

185

0

0

3,672

-72

2,096

5,134

1,500

992

504

176

-592

0

9,738

05/08/20Peep 2010.1

Table D-3




Economic SummaryBlock PL 18, Surat Basin, Queensland, Australia - Probable Undeveloped



Company (% of Total) 91.46 0.00 100.00 100.00

Company (% of Contr) 100.00 0.00 100.00 100.00

Partner (% of Contr) 0.00 0.00 0.00 0.00

Contr 91.46 0.00 100.00 100.00

NOC 0.00 0.00 0.00 0.00







0 5,767 4,470 1.48 1.1

5.0 5,187 4,100 1.43 1.1

10.0 4,692 3,773 1.39 1.1

15.0 4,267 3,484 1.35 1.1

20.0 3,898 3,226 1.31 1.1

25.0 3,576 2,997 1.27 1.0

AT ROR (%) >800.00 Contr Take (%) 57.2




Net Revenue 13,467 100.00 108.07

Less:



Tariffs 0 0.00 0.00


Capital Costs 3,897 28.93 31.27





Oil (MSTB) 140 140

Gas (MMSCF) 0 0

NGL (MSTB) 0 0

Tax (MSTB) - -


Project Company





Economic Summary

Date

CompanySales

Revenue

M$US

SuratOver

RidingRoyalty

M$US

QueenslandRoyalty

M$US

OperatingCosts

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

Cash FlowTotal

M$US

PRRT&

IncomeTax

M$US

After Tax

Cash FlowTotal

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

Total

0

8,570

3,962

1,697

497

0

0

14,725

0

224

101

42

11

0

0

377

0

745

336

139

38

0

0

1,258

72

1,443

943

658

312

0

0

3,427

0

0

0

0

0

0

0

0

0

3,684

0

0

0

0

0

3,684

0

0

0

0

212

0

0

212

0

0

0

0

0

0

0

0

-72

2,474

2,582

859

-77

0

0

5,767

0

0

709

461

126

0

0

1,296

-72

2,474

1,873

397

-202

0

0

4,470

05/08/20Peep 2010.1

Table D-3A




Production DetailBlock PL 18, Surat Basin, Queensland, Australia - Probable Undeveloped


production detail 1

Date# of Oil

Wells

ProjectOil

Rate

Bbl/d

ProjOil

Volume

MSTB

CompanyGross

OilVolume

MSTB

CompanyNetOil

Volume

MSTB

OilPrice

$US/Bbl

# of GasWells

ProjectGasRate

mcf/d

ProjectGas

Volume

MMSCF

CompanyGross

GasVolume

MMSCF

CompanyNet

GasVolume

MMSCF $US/M2013(12)

2014(12)

2015(12)2016(12)

2017(12)

2018(12)

2019(12)

Total

0.0

1.8

2.02.0

2.0

0.0

0.0

---

0

221

10744

21

0

0

---

0

81

3916

5

0

0

140

0

81

3916

5

0

0

140

0

71

3514

4

0

0

125

112.10

106.34

101.67105.53

109.15

0.00

0.00

---

0.0

0.0

0.00.0

0.0

0.0

0.0

---

0

0

00

0

0

0

0

0

0

00

0

0

0

0

0

0

00

0

0

0

0

0

0

00

0

0

0

0


Date

ProjectNGLRate

Bbl/d

ProjectNGL

Volume

MSTB

CompanyGross

NGLVolume

MSTB

CompanyNet

NGLVolume

MSTB

NGLPrice

$US/Bbl

ProjectBOERate

Bbl/d

ProjectBOE

Volume

MBOE

CompanyGross

BOEVolume

MBOE

CompanyNet

BOEVolume

MBOE

TotalProject

SalesRevenue

M$US

TotalCompany

SalesRevenue

M$US

B

$2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

Total

0

0

0

0

0

0

0

---

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0.00

0.00

0.00

0.00

0.00

0.00

0.00

---

0

221

107

44

21

0

0

---

0

81

39

16

5

0

0

140

0

81

39

16

5

0

0

140

0

71

35

14

4

0

0

125

0

8,570

3,962

1,697

497

0

0

14,725

0

8,570

3,962

1,697

497

0

0

14,725

05/08/20Peep 2010.1

Table D-3A




Revenue & Burden DetailBlock PL 18, Surat Basin, Queensland, Australia - Probable Undeveloped



DateOil

Revenue

M$US

GasRevenue

M$US

NGLRevenue

M$US

TotalSales

Revenue

M$US

Fixed

M$US

VariableOil

M$US

Well Oil

M$US

VariableGas

M$US

WellGas

M$US

Processing

M$US

OilTransport

M$US2013(12)

2014(12)

2015(12)2016(12)

2017(12)

2018(12)

2019(12)

Total

0

8,570

3,9621,697

497

0

0

14,725

0

0

00

0

0

0

0

0

0

00

0

0

0

0

0

8,570

3,9621,697

497

0

0

14,725

72

325

343348

193

0

0

1,280

0

0

00

0

0

0

0

0

0

00

0

0

0

0

0

0

00

0

0

0

0

0

0

00

0

0

0

0

0

96

9899

59

0

0

352

0

1,023

502210

60

0

0

1,795


Date

SuratOver

RidingRoyalties

M$US

QueenslandRoyalty

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

CashFlow

M$US

PRRT

M$US

IncomeTax

M$US

After Tax

CashFlow

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

Total

0

224

101

42

11

0

0

377

0

745

336

139

38

0

0

1,258

0

0

0

0

0

0

0

0

0

3,684

0

0

0

0

0

3,684

0

0

0

0

212

0

0

212

0

0

0

0

0

0

0

0

-72

2,474

2,582

859

-77

0

0

5,767

0

0

0

0

0

0

0

0

0

0

709

461

126

0

0

1,296

-72

2,474

1,873

397

-202

0

0

4,470

05/08/20Peep 2010.1

Table D-3A




Economic SummaryBlock PL 18, Surat Basin, Queensland, Australia - Total Possible



Company (% of Total) 91.34 0.00 100.00 100.00

Company (% of Contr) 100.00 0.00 100.00 100.00

Partner (% of Contr) 0.00 0.00 0.00 0.00

Contr 91.34 0.00 100.00 100.00

NOC 0.00 0.00 0.00 0.00







0 11,608 5,267 1.60 0.8

5.0 9,665 4,593 1.53 0.8

10.0 8,129 4,023 1.46 0.8

15.0 6,900 3,540 1.39 0.8

20.0 5,905 3,129 1.33 0.7

25.0 5,093 2,778 1.27 0.7

AT ROR (%) >800.00 Contr Take (%) 40.9




Net Revenue 25,200 100.00 108.93

Less:



Tariffs 0 0.00 0.00


Capital Costs 7,241 28.73 31.30





Oil (MSTB) 261 261

Gas (MMSCF) 0 0

NGL (MSTB) 0 0

Tax (MSTB) - -


Project Company





Economic Summary

Date

CompanySales

Revenue

M$US

SuratOver

RidingRoyalty

M$US

QueenslandRoyalty

M$US

OperatingCosts

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

Cash FlowTotal

M$US

PRRT&

IncomeTax

M$US

After Tax

Cash FlowTotal

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

1,484

9,138

7,520

4,668

2,836

1,593

350

0

27,589

0

39

239

198

122

72

39

8

0

717

0

131

798

659

406

239

130

27

0

2,389

0

190

1,314

1,159

996

975

797

203

0

5,634

0

0

0

0

0

0

0

0

0

0

0

1,501

3,740

1,547

0

0

0

0

0

6,787

0

0

0

0

-212

0

0

666

0

454

0

0

0

0

0

0

0

0

0

0

0

-378

3,047

3,958

3,357

1,550

627

-554

0

11,608

0

0

-214

2,856

2,163

1,046

451

38

0

6,341

0

-378

3,260

1,102

1,194

504

176

-592

0

5,267

05/08/20Peep 2010.1

Table D-3B




Production DetailBlock PL 18, Surat Basin, Queensland, Australia - Total Possible


production detail 1

Date# of Oil

Wells

ProjectOil

Rate

Bbl/d

ProjOil

Volume

MSTB

CompanyGross

OilVolume

MSTB

CompanyNetOil

Volume

MSTB

OilPrice

$US/Bbl

# of GasWells

ProjectGasRate

mcf/d

ProjectGas

Volume

MMSCF

CompanyGross

GasVolume

MMSCF

CompanyNet

GasVolume

MMSCF $US/M2013(12)

2014(12)

2015(12)2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0.0

0.3

2.84.0

4.8

5.0

4.4

4.0

0.0

---

0

38

246195

117

70

39

25

0

---

0

14

9071

43

26

14

3

0

261

0

14

9071

43

26

14

3

0

261

0

12

8063

38

23

13

3

0

231

0.00

106.34

101.67105.53

109.15

110.75

112.37

114.02

0.00

---

0.0

0.0

0.00.0

0.0

0.0

0.0

0.0

0.0

---

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0


Date

ProjectNGLRate

Bbl/d

ProjectNGL

Volume

MSTB

CompanyGross

NGLVolume

MSTB

CompanyNet

NGLVolume

MSTB

NGLPrice

$US/Bbl

ProjectBOERate

Bbl/d

ProjectBOE

Volume

MBOE

CompanyGross

BOEVolume

MBOE

CompanyNet

BOEVolume

MBOE

TotalProject

SalesRevenue

M$US

TotalCompany

SalesRevenue

M$US

B

$2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

0

0

0

0

0

0

0

0

---

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

---

0

38

246

195

117

70

39

25

0

---

0

14

90

71

43

26

14

3

0

261

0

14

90

71

43

26

14

3

0

261

0

12

80

63

38

23

13

3

0

231

0

1,484

9,138

7,520

4,668

2,836

1,593

350

0

27,589

0

1,484

9,138

7,520

4,668

2,836

1,593

350

0

27,589

05/08/20Peep 2010.1

Table D-3B




Revenue & Burden DetailBlock PL 18, Surat Basin, Queensland, Australia - Total Possible



DateOil

Revenue

M$US

GasRevenue

M$US

NGLRevenue

M$US

TotalSales

Revenue

M$US

Fixed

M$US

VariableOil

M$US

Well Oil

M$US

VariableGas

M$US

WellGas

M$US

Processing

M$US

OilTransport

M$US2013(12)

2014(12)

2015(12)2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

1,484

9,1387,520

4,668

2,836

1,593

350

0

27,589

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

1,484

9,1387,520

4,668

2,836

1,593

350

0

27,589

0

13

156227

386

528

500

125

0

1,936

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

0

0

0

0

0

0

0

0

00

42

102

104

35

0

283

0

177

1,157931

567

345

194

43

0

3,414


Date

SuratOver

RidingRoyalties

M$US

QueenslandRoyalty

M$US

Tariffs

M$US

Capital

M$US

Aband

M$US

CarbonTax

M$US

BeforeTax

CashFlow

M$US

PRRT

M$US

IncomeTax

M$US

After Tax

CashFlow

M$US2013(12)

2014(12)

2015(12)

2016(12)

2017(12)

2018(12)

2019(12)

2020(12)

2021(12)

Total

0

39

239

198

122

72

39

8

0

717

0

131

798

659

406

239

130

27

0

2,389

0

0

0

0

0

0

0

0

0

0

0

1,501

3,740

1,547

0

0

0

0

0

6,787

0

0

0

0

-212

0

0

666

0

454

0

0

0

0

0

0

0

0

0

0

0

-378

3,047

3,958

3,357

1,550

627

-554

0

11,608

0

0

0

1,647

1,366

649

266

38

0

3,965

0

0

-214

1,209

798

397

185

0

0

2,375

0

-378

3,260

1,102

1,194

504

176

-592

0

5,267

05/08/20Peep 2010.1

Table D-3B



References – Page 1

4325.70684.IB

J:\Chelsea Oil and Gas\Report\Chelsea Summary.doc

References

Australia Government Site, Geoscience Australia, www.ga.gov.au

Baker J.C., Price P.L. and Golding S.D. (1991) Coal as a source rock for hydrocarbon gas in

the Aldebaran Sandstone, Denison Trough, Bowen Basin - geochemical evidence. In:

Queensland Coal Symposium (Edited by Griffiths P.). The Australasian Institute of Mining

and Metallurgy Southern Queensland Branch, 57-61.

Dickins, J.W. and Malone E.J. (1973) Geology of the Bowen Basin, Queensland, Department

of Mineral and Energy, Bureau of Mineral Resources, Geology and Geophysics, Bulletin 130,

Australian Government Publishing Service, Canberra, Australia.

Exon N.F. (1976) Geology of the Surat Basin in Queensland, Department of National

Resources, Bureau of Mineral Resources, Geology and Geophysics, Bulletin 166, Australian

Government Publishing Service, Canberra, Australia.

Fielding C.R., Falkner A.J., Kassan J., and Draper J.J. (1990) Permian and Triassic

depositional systems in the Bowen Basin. Proceedings of the Bowen basin symposium,

Mackay, 1990. Geological Society of Australia, Queensland Division, 21-5.

Hawkins P.J., Jackson K.S., and Horvath Z. (1992) Regional geology, petroleum geology,

and hydrocarbon potential of the southern Taroom Trough, Bowen Basin, Queensland.

Queensland Geology 3, 1-42.

Jackson K.S, Hawkins P.J. and Bennett A.J.R. (1980). Regional facies and geochemical

evaluation of the southern Denison Trough, Queensland. The APEA Journal 20, 143-58.

Summons Roger E., Zumberge John E., Boreham Christopher J., Bradshaw Marita T., Brown

Stephen W., Edwards Dianne S., Hope Janet M. and Johns Natalie (2002), Geoscience

Australia Canberra Geomark Research Houston, The Oils Of Eastern Australia Petroleum

Geochemistry And Correlation Volumes 1 and 2, Bowen-Surat And Cooper-Eromanga

Basins.

Thomas B.N. and Reiser R.F. (1968) The Geology of the Surat 1:250,000 Sheet Area,

Department of National Resources, Bureau of Mineral Resources, Geological Survey of

Queensland, Record 1968/56.

http://www.ga.gov.au/






References – Page 2

4325.70684.IB.smr


Thomas B.M., Osborne D.G. and Wright A.J. (1982) Hydrocarbon habitat of the

Bowen/Surat Basin. The APEA Journal 22, 213-26.

Wikipedia, the free encyclopedia, www.en.wikipedia.org

http://www.en.wikipedia.org/





Figure 1

70684

Map of Eastern Australia Showing Locations of theBowen and Surat Basins Together with Adjacent Sedimentary Basins

Summons et al (2002)



Figure 2

70684

Location Map Showing the Geographic Distribution of Oil and Gas in theBowen and Surat Basins

Client Area

Summons et al (2002)



70684

PL 18 and PL280 (Surat Assets) Location Map

PL 18

PL 280

http://w



Figure 4

70684

Bowen/Surat Basin Stratigraphic Column

http://www.bountyoil.com/

Primary Reservoir Target

Source



70684Seismic Basemap with Wells, Block Areas and Fault Poly

Block PL18Area = 185.5 KM

Block PL280Area = 90.6 KM2



70684

Seismic Basemap with Wells and Fault Polygons

Block PL280



70684

Fault Framework From Interpreted Fault Sticks

Block PL

Block PL280



70684Time Structure Map of Showgrounds



70684Depth Structure Map of Showgrounds

Yellowbank Creek

Yellowbank Creek North

Beardmore Field

McWhirter Field

Thomby Creek Field

McGregor Field



70684Thomby Creek Field - Seismic Line-SD87-4

W



70684

Thomby Creek Field - Seismic Line-86B-4

Evergreen

Showgrounds

Basement

NNE



70684Thomby Creek Field – Seismic Line-SD87-17A

NNE



70684McWhirter Field – Seismic Line-86B-24

NW



70684McGregor Field – Seismic Line-86B-23

NW



70684McGregor Field – Seismic Line-81B-3

W



70684Yellowbank Creek North Field – Seismic Line-85B-5

Yellowbank Creek North-1

W



70684Yellowbank Creek 1 Well - Seismic Line-78B-29

Yellowbank Creek-1W



70684Yellowbank Creek Field – Seismic Line-85B-6

Yellowbank Creek-3

W



70684Yellowbank Creek Field – Seismic Line-81B-2

W



70684Beardmore Field – Seismic Line-81T-21

W



70684

Beardmore Field – Seismic Line-85-S2

Beardmore Southwest-1AW



70684

3D Perspective View of Showgrounds Depth Structure M



70684

3D Perspective View of Base of Showgrounds Depth Structu



Figure 24

70684

Well Thomby Creek 2: Cementation Factor from Core Data



Figure 25

70684

Thomby Creek-1 Well Logs

S h o w g r o u

n d s S S T



Figure 26

70684

Thomby Creek

McWhirter

YelowbankCreek North

Beardmore

YellowbankCreek

Top Showgrounds Sandstone Formation Depth Structure Map



70684

Thomby Creek Field Volume Areas Assignment

OWC



Figure 28

70684

McWhirter South

East

West

McWhirter North

ODT

Spill Point

Probable

Possible

2C

3C

Low

Best

High

PL280/PL18

McWhirter Field Volume Areas Assignment



Figure 29

70684

ODT

Spill Point Low

BestHigh

Yellowbank Creek Field Volume Areas Assignment



Figure 30

70684

Beardmore Field Volume Areas Assignment

ODT

Spill Point

Low

Best

High

PL280/PL18



Figure 31

70684

MCGREGOR 1

YELLOWBANK CREEK 1

YELLOWBANK CREEK NORTH 1

- 1 5 7 3

- 1 5 7 3

- 1 5 7 3

- 1 5 7 3

- 1 5 7 3

697600 697800 698000 698200 698400 698600 698800 699000

697600 697800 698000 698200 698400 698600 698800 699000 6 9 3 0 4 0 0

6 9 3 0 6 0 0

6 9 3 0 8 0 0

6 9 3 1 0 0 0

6 9 3 1 2 0 0

6 9 3 1 4 0 0

6 9 3 1 6 0 0

6 9 3 1 8 0 0

6 9 3 2 0

0 0

6 9 3 2 2 0 0

6 9 3 2 4 0 0

6 9 3 2 6 0 0

6 9 3 2 8 0 0

6 9 3 3 0 0 0

6 9 3 0 4 0 0

6 9 3 0 6 0 0

6 9 3 0 8 0 0

6 9 3 1 0 0 0

6 9 3 1 2 0 0

6 9 3 1 4 0 0

6 9 3 1 6 0 0

6 9 3 1 8 0 0

6 9

3 2 0 0 0

6 9 3 2 2 0 0

6 9 3 2 4 0 0

6 9 3 2 6 0 0

6 9 3 2 8 0 0

6 9 3 3 0 0 0

0 100 200 300 400 500m

1:10240

Yellowbank Creek North Field Volume Areas Assignment

OWC

Possible



Figure 32

70684

McGregor Field Volume Areas Assignment

MCGREGOR 1

YELLOWBANK CREEK 1

YELLOWBANK CREEK NORTH 1

- 1

5

-15 85

- 1 5 8 0

- 1 5 8 5

- 1 5 8 0

- 1 5 8 5

- 1 5 8 5

- 1 5 8 5

- 1 5 8 0

- 1 5 8 5

- 1 5 8 0

- 1 5 8 0

1 5 8 5

-1585

-1580

-1585

-15 8 0

- 1 5 8 5

- 1 5 8 0

- 1 5 8 5

697000 697200 697400 697600 697800 698000 698200 698400 698600 698800 699000

697000 697200 697400 697600 697800 698000 698200 698400 698600 698800 699000

6 9 3 1 0 0 0

6 9 3 1 2 0 0

6 9

3 1 4 0 0

6 9 3 1 6 0 0

6 9 3 1 8 0 0

6 9 3 2 0 0 0

6 9 3 2 2 0

0

6 9 3 2 4 0 0

6 9 3 2 6 0 0

6 9 3 2 8 0 0

6 9 3 3 0 0 0

6 9 3 3 2 0 0

6 9 3 3 4 0 0

6 9 3 3 6 0 0

6 9 3 3 8 0 0

6 9 3 4

0 0 0

6 9 3 4 2 0 0

6 9 3 1 0 0 0

6 9 3 1 2 0 0

6 9 3 1 4

0 0

6 9 3 1 6 0 0

6 9 3 1 8 0 0

6 9 3 2 0 0 0

6 9 3 2 2 0 0

6 9 3 2 4 0 0

6 9 3 2 6 0 0

6 9 3 2 8 0 0

6 9 3 3 0 0 0

6 9 3 3 2 0 0

6 9 3 3 4 0 0

6 9 3 3 6 0 0

6 9 3 3 8 0 0

6 9 3 4 0 0 0

6 9 3 4 2 0 0

0 100 200 300 400 500m

1:12824

Low

Best

High



Appendix A — Page 1

4325.70684.IB.smr

J:\Chelsea Oil & Gas 70684\Report\Appendices\Appendix A - Definitions.doc

Appendix A — Definitions

The following definitions form the basis of our classification of reserves and values

presented in this report. They have been prepared by the Standing Committee on Reserves

Definitions of the Petroleum Society of the CIM (“CIM”), incorporated in the Society of

Petroleum Evaluation Engineers (“SPEE”) Canadian Oil and Gas Evaluation Handbook

(“COGE Handbook”) and specified by National Instrument 51-101 (“NI 51-101”).

Reserves are estimated remaining quantities of oil and natural gas and related substances

anticipated to be recoverable from known accumulations, from a given date forward, based

on:

• analysis of drilling, geological, geophysical and engineering data;

• the use of established technology;

•

specified economic conditions, which are generally accepted as being reasonable,

and shall be disclosed; and

• a remaining reserve life of 50 years.

Reserves are classified according to the degree of certainty associated with the estimates.

1. Proved Reserves

Proved reserves are those reserves that can be estimated with a high degree of certainty

to be recoverable. It is likely that the actual remaining quantities recovered will exceed

the estimated proved reserves.

2. Probable Reserves

Probable reserves are those additional reserves that are less certain to be recovered

than proved reserves. It is equally likely that the actual remaining quantities recovered

will be greater or less than the sum of the estimated proved plus probable reserves.

3. Possible Reserves

Possible reserves are those additional reserves that are less certain to be recovered thanprobable reserves. It is unlikely that the actual remaining quantities recovered will

exceed the sum of the estimated proved plus probable plus possible reserves. Possible

reserves have not been considered in this report.




4325.70684.IB.smr


Other criteria that must also be met for the categorization of reserves are provided in

Section 5.5 of the COGE Handbook.

Each of the reserves categories (proved, probable, and possible) may be divided into

developed or undeveloped categories.

4. Developed Reserves

Developed reserves are those reserves that are expected to be recovered from existing

wells and installed facilities or, if facilities have not been installed, that would involve a

low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves

on production. The developed category may be subdivided into producing and non-

producing.

5. Developed Producing Reserves

Developed producing reserves are those reserves that are expected to be recovered

from completion intervals open at the time of the estimate. These reserves may be

currently producing or, if shut in, they must have previously been on production, and

the date of resumption of production must be known with reasonable certainty.

6. Developed Non-Producing Reserves

Developed non-producing reserves are those reserves that either have not been on

production, or have previously been on production, but are shut in, and the date ofresumption 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




4325.70684.IB.smr


specific wells, facilities, and completion intervals in the pool and their respective

development and production status.

8. Levels of Certainty for Reported Reserves

The qualitative certainty levels contained in the definitions in Sections 1, 2 and 3 are

applicable to individual reserves entities, which refers to the lowest level at which

reserves estimates are made, and to reported reserves, which refers to the highest level

sum of individual entity estimates for which reserve estimates are made.

Reported total reserves estimated by deterministic or probabilistic methods, whether

comprised of a single reserves entity or an aggregate estimate for multiple entities,

should target the following levels of certainty under a specific set of economic

conditions:

a. There is a 90% probability that at least the estimated proved reserves will be

recovered.

b. There is a 50% probability that at least the sum of the estimated proved reserves

plus probable reserves will be recovered.

c. There is a 10% probability that at least the sum of the estimated proved reserves

plus probable reserves plus possible reserves will be recovered.

A quantitative measure of the probability associated with a reserves estimate isgenerated only when a probabilistic estimate is conducted. The majority of reserves

estimates will be performed using deterministic methods that do not provide a

quantitative measure of probability. In principle, there should be no difference between

estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the

effect of aggregation is provided in Section 5.5.3 of the COGE Handbook. Whether

deterministic or probabilistic methods are used, evaluators are expressing their

professional judgement as to what are reasonable estimates.

9. Remaining Recoverable Reserves are the total remaining recoverable reserves

associated with the acreage in which the Company has an interest.

10. Company Gross Reserves are the Company’s working interest share of the remaining

reserves, before deduction of any royalties.




4325.70684.IB.smr


11. 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.

12. Net Production Revenue is income derived from the sale of net reserves of oil, non-

associated and associated gas, and gas by-products, less all capital and operating costs.

13. Fair Market Value is defined as the price at which a purchaser seeking an economic

and commercial return on investment would be willing to buy, and a vendor would be

willing to sell, where neither is under compulsion to buy or sell and both are competent

and have reasonable knowledge of the facts.

14. Barrels of Oil Equivalent (BOE) Reserves – BOE is the sum of the oil reserves, plus

the gas reserves divided by a factor of 6, plus the natural gas liquid reserves, all

expressed in barrels or thousands of barrels. Equivalent reserves can also be expressed

in thousands of cubic feet of gas equivalent (McfGE) using a conversion ratio of 1 bbl:6

Mcf.

15. Oil (or Crude Oil) – a mixture consisting mainly of pentanes and heavier hydrocarbons

that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure

and temperature. Crude oil may contain small amounts of sulphur and other non-

hydrocarbons, but does not include liquids obtained from the processing of natural gas.

16. Gas (or Natural Gas) – a mixture of lighter hydrocarbons that exist either in thegaseous phase or in solution in crude oil in reservoirs, but are gaseous at atmospheric

conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.

17. Non-Associated Gas – an accumulation of natural gas in a reservoir where there is no

crude oil.

18. Associated Gas – the gas cap overlying a crude oil accumulation in a reservoir.

19. Solution Gas – gas dissolved in crude oil.

20. Natural Gas Liquids – those hydrocarbon components that can be removed from

natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes

plus, condensate, and small quantities of non-hydrocarbons.



Appendix B — Page 1

4325.70684.IB.smr

J:\Chelsea Oil & Gas 70684\Report\Appendices\Appendix B - Prices (March 31, 2013).doc

Appendix B — Prices (As of March 31, 2013)

Sproule’s short-term outlook for oil and gas prices adopts the NYMEX futures market for the

forecast period ending March 31, 2016. The forecast used in this evaluation was derived

as of March 31, 2013, 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

April 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, and the gas price forecasts are based on the NYMEX Division Henry Hub natural

gas futures contract.

The NYMEX oil and gas futures prices are the foundation of Sproule’s energy pricing models

in the early years. This data is combined with Sproule’s assumptions respecting long-term

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

and prices of competing fuels, to forecast wellhead and plantgate prices for Canadian oil,

natural gas, and natural gas by-product production. The following paragraphs briefly

describe some of the key considerations included in Sproule’s long-term outlook for oil and

natural gas price forecasts.

Oil Prices

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 for

the next 10 years. A strong demand for crude oil, instability in the Middle East, and the

increasing cost of exploration and development has served to increase the price of crude oilthroughout the world. In recognition of these factors, Sproule's long-term forecast has been

set at $90.00 US per barrel (2013 dollars).

The oil price forecasts set out in Table S-2 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 UK Brent prices were forecast

based on historical pricing relationships to WTI. 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

trading hub.



Appendix C — Page 1

4325.70684.IB.smr

J:\Chelsea Oil & Gas 70684\Report\Appendices\Appendix C -International Abbrev and Conv Factors.doc

Appendix C — Abbreviations, Units and Conversion Factors

This appendix contains a list of abbreviations found in Sproule reports, a table comparing

Imperial and Metric units, and conversion tables used to prepare this report.

Abbreviations

AFE authority for expenditure

AOF absolute open flow

APO after pay out

Bg gas formation volume factor

Bo oil formation volume factor

bopd barrels of oil per day

bfpd barrels of fluid per day

BPO before pay out

BS&W basic sediment and water

BTU British thermal unit

bwpd barrels of water per day

CF casing flange

CGR condensate gas ratio

D&A dry and abandoned

DCQ daily contract quantity

DSU drilling spacing unit

DST drill stem testEOR enhanced oil recovery

EPSA exploration and production sharing agreement

FVF formation volume factor

GOR gas-oil ratio

GORR gross overriding royalty

GWC gas-water-contact

HCPV hydrocarbon pore volume

ID inside diameter

IOR improved oil recovery

IPR inflow performance relationshipIRR internal rate of return

k permeability

KB kelly bushing

LKH lowest known hydrocarbons

LNG liquefied natural gas




4325.70684.IB.smr


LPG liquefied petroleum gas

md millidarcies

MDT modular formation dynamics tester

MPR maximum permissive rate

MRL maximum rate limitation

NGL natural gas liquids

NORR net overriding royalty

NPI net profits interest

NPV net present value

OD outside diameter

OGIP original gas in place

OOIP original oil in place

ORRI overriding royalty interest

OWC oil-water-contact

P1 proved

P2 probable

P3 possible

P&NG petroleum and natural gas

PI productivity index

ppm parts per million

PSU production spacing unit

PSA production sharing agreement

PSC production sharing contract

PVT pressure-volume-temperature

RFT repeat formation testerRT rotary table

SCAL special core analysis

SS subsea

TVD true vertical depth

WGR water gas ratio

WI working interest

WOR water oil ratio

2D two-dimensional

3D three-dimensional

4D four-dimensional1P proved

2P proved plus probable

3P proved plus probable plus possibleoAPI degrees API (American Petroleum Institute)




4325.70684.IB.smr


Imperial and Metric Units

Imperial Units Metric Units

M (103) one thousand Prefixes k (103) one thousand

MM (106) Million M (106) million

B (109) one billion T (1012) one billion

T (1012) one trillion E (1018) one trillion

G (109) one milliard

in. Inches Length cm centimetres

ft Feet m metres

mi Mile km kilometres

ft2 square feet Area m2 square metres

ac Acres ha hectares

cf or ft3 cubic feet Volume m3 cubic metres

scf Standard cubic feet

gal Gallons L litres

Mcf Thousand cubic feet

Mcfpd Thousand cubic feet per day

MMcf million cubic feet

MMcfpd million cubic feet per day

Bcf billion cubic feet (109)

bbl Barrels m3 cubic metre

Mbbl Thousand barrels

stb stock tank barrel stm3 stock tank cubic metres

bbl/d barrels per day m3 /d cubic metre per day

bbl/mo barrels per month

Btu British thermal units Energy J joules

MJ/m3 megajoules per cubic metre (106)

TJ/d terajoule per day (1012)

oz ounce Mass g gram

lb pounds kg kilograms

ton ton t tonne

lt long tons

Mlt thousand long tons

psi pounds per square inch Pressure Pa pascals

kPa kilopascals (103)

psia pounds per square inch absolute

psig pounds per square inch gauge

°F degrees Fahrenheit Temperature °C degrees Celsius

°Rdegrees Rankine K Kelvin

M$ thousand dollars Dollars k$ thousand dollars




4325.70684.IB.smr


Imperial and Metric Units (Cont’d)

Imperial Units Metric Units

sec second Time s second

min minute min minute

hr hour h hour

day day d day

wk week week

mo month month

yr year a annum




4325.70684.IB.smr


Conversion Tables

Conversion Factors — Metric to Imperial

cubic metres (m3) (@ 15°C) x 6.29010 = barrels (bbl) (@ 60°F), water

m3 (@ 15°C) x 6.3300 = bbl (@ 60°F), Ethane

m3 (@ 15°C) x 6.30001 = bbl (@ 60°F), Propane

m3 (@ 15°C) x 6.29683 = bbl (@ 60°F), Butanes

m3 (@ 15°C) x 6.29287 = bbl (@ 60°F), oil, Pentanes Plus

m3 (@ 101.325 kPaa, 15°C) x 0.0354937 = thousands of cubic feet (Mcf) (@ 14.65 psia, 60°F)

1,000 cubic metres (103m3) (@ 101.325 kPaa, 15°C) x 35.49373 = Mcf (@ 14.65 psia, 60°F)

hectares (ha) x 2.4710541 = acres

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

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

m3 /103m3 (@ 101.325 kPaa, 15° C) x 0.0437809 = Mcf/Ac.ft. (@ 14.65 psia, 60°F)

joules (j) x 0.000948213 = Btu

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

15°C)

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

(@ 14.65 psia, 60°F)

dollars per gigajoule ($/GJ) x 1.054615 = $/Mcf (1,000 Btu gas)

metres (m) x 3.28084 = feet (ft)

kilometres (km) x 0.6213712 = miles (mi)

dollars per 1,000 cubic metres ($/103m3) x 0.0288951 = dollars per thousand cubic feet ($/Mcf) (@ 15.025 psia) B.C.

($/103m3) x 0.02817399 = $/Mcf (@ 14.65 psia) Alta.

dollars per cubic metre ($/m3) x 0.158910 = dollars per barrel ($/bbl)

gas/oil ratio (GOR) (m3 /m3) x 5.640309 = GOR (scf/bbl)

kilowatts (kW) x 1.341022 = horsepower

kilopascals (kPa) x 0.145038 = psi

tonnes (t) x 0.9842064 = long tons (LT)

kilograms (kg) x 2.204624 = pounds (lb)

litres (L) x 0.2199692 = gallons (Imperial)

litres (L) x 0.264172 = gallons (U.S.)

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

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

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

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

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

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

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

millipascal seconds (mPa.s) x 1.0 = centipoise




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 .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 (104

m3

) (ha.m)

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

Btu x 1054.615 = joules (J)

British thermal units per standard cubic foot (Btu/Scf) (@ 14.65 psia, 60°F) x .03743222 = megajoules per cubic metre (MJ/m3) (@ 101.325 kPaa, 15°C)

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

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

$/Mcf (@ 15.025 psia, 60°F), B.C. x 34.607860 = $/103m3 (@ 101.325 kPaa, 15°C)

feet (ft) x 0.3048 = metres (m)

miles (mi) x 1.609344 = kilometres (km)

$/bbl x 6.29287 = $/m3 (average for 30°-50° API)

GOR (scf/bbl) x 0.177295 = gas/oil ratio (GOR) (m3 /m3)

horsepower x 0.7456999 = kilowatts (kW)

psi x 6.894757 = kilopascals (kPa)

long tons (LT) x 1.016047 = tonnes (t)

pounds (lb) x 0.453592 = kilograms (kg)

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