ASX ANNOUNCEMENT

22nd December 2015

DEMPSEY UPDATE ON PETROZ LIMITED ACQUISITION

As previously announced to the market on 4 September 2015, Dempsey Minerals Limited ("Dempsey" or "the Company") entered into a conditional exclusive Option and Sale & Purchase Agreement ("Agreement") under which it had an option to acquire 100% of the issued capital of Petroz Limited ("Petroz") ("Option"). Petroz is an unlisted public Australian oil company, which holds a 75% interest in the proven and awarded, Licence 21A Alasehir & Sarikiz Oil Fields located in Western Turkey ("Licence").

The Company is pleased to present an update on the due diligence, acquisition process and capital raising plans.

Loan Obligations under Agreement

Under the Agreement, Dempsey agreed to make a loan of \$700,000 available to Petroz for the purposes of paying the required GDPA (Turkish Petroleum Authority) bonds to secure the Licence and to pay other costs associated with the Licence. Dempsey has now provided that loan to Petroz and all relevant government bonds are now in place and registered. The loan was paid out of the Company's existing working capital.

The loan is unsecured, non-interest bearing and will be treated as an intercompany loan by Dempsey if the acquisition of Petroz ("Acquisition") is completed. If Dempsey does not exercise the Option, or if the Acquisition is not completed, the loan must be repaid in full within one (1) month of the relevant circumstance occurring. Dempsey may allow for the loan to be repaid by way of the issue of a corresponding number of fully paid ordinary shares in the capital of Petroz, to be calculated at a price of \$0.05 per Petroz share.

In addition, the Company is now in receipt of an Independent Expert Report on the Licence (see below) which was commissioned by Dempsey as part of the due diligence process.

Capital Raising

Dempsey wishes to advise that it has recently completed a capital raise of \$68,250, with 975,000 fully paid ordinary shares in the Company ("Shares") being issued at a price of \$0.07 per Share.

As stated in its announcement dated 4 September 2015, the Company also proposed an entitlement offer as part of its capital raising strategy. The proposed terms of that entitlement offer are set out below. The terms of the entitlement offer will be finalised, approved and distributed to Dempsey shareholders in due course.

The Company now proposes to make an entitlement offer to existing Dempsey shareholders of up to 6,095,000 Shares on the basis of one (1) new Share ("New Share") for every five (5) Shares held on the

record date at a price of \$0.07 per New Share together with one (1) free attaching option (exercisable at \$0.14 with a 3 year exercise term) for every one (1) new Shares subscribed for.

In addition, as part of the entitlement offer the Company proposes to offer options to those shareholders listed on the Company's register on the record date, also on a one (1) for five (5) basis at a price of \$0.01 each (exercisable at \$0.14 with a 3 year exercise term). This aims to raise a further \$60,950.

If the entitlement offer is fully taken up a total of \$487,600 will be raised by the Company. The funds raised will be used to fund the administrative costs of the acquisition including the costs of assessing the business, operations and prospects of Petroz for due diligence purposes, advisers' fees, for working capital for the existing business operations of the Company and, if the Option is exercised, to cover the costs of seeking shareholder approval for the Acquisition and the costs of achieving re-compliance with the admission requirements under the ASX Listing Rules. If the Option is not exercised this amount will be used for administrative costs already then incurred in respect of the Acquisition and for general working capital for the Company and its existing operations.

Acquisition Completion

In the event of the exercise of the Option, ASX Listing Rules 11.1.2 and 11.1.3 will apply to the Acquisition. Hence Dempsey shareholder approval, re-compliance with Chapters 1 and 2 of the ASX Listing Rules and ASX approval for re-admission of Dempsey to the official list of ASX are required as a condition precedent to completion of the Acquisition.

Independent Expert's Report

As part of the due diligence process involved with the Agreement, Dempsey engaged the services of RISC Operations Pty Limited ("RISC") to prepare an Independent Expert's Report ("IER") in relation to Petroz's 75% interest in the Licence.

The IER incorporates RISC's assessment of Petroz's petroleum resources and associated development schedules, production, cost forecasts and discounted cash flow of the un-risked contingent resources. In addition, RISC used its expertise to make necessary adjustments to provide Dempsey with current information and a reasonable assessment of the resources.

A complete copy of the RISC report is attached to this release.

RISC carried out an independent resource estimate for the Alasehir and Sarikiz oil fields and estimated 2C contingent resources net to Petroz of 6.8 million US stock tank barrels ("MMstb") and a further best estimate of unrisked net prospective resources of 6.7 MMstb. The results of RISC's analysis are shown in the tables below.

Contingent Resources as at 30 September 2015
Field		Gross (100%) MMstb		Net Petroz (75%) MMstb
	1 ^C	2C	3C	1 ^C	2C	3C
Sarikiz	1.4	3.1	5.8	1.1	2.3	4.4
Alasehir	2.5	6.0	12.5	1.9	4.5	9.4
Total	3.9	9.1	18.3	3.0	6.8	13.7

RISC has classified estimates of future recovery from the Sarikiz and Alasehir fields as contingent resources. RISC has advised that contingent resources carry with them a risk that commercial development is subject to encouraging results from the drilling, testing and evaluation of future Sarikiz and Alasehir wells.

Prospective Resources as at 30 September 2015
Field	Net Petroz (75%) MMstb Gross (100%) MMstb
	Low	Best	High	Low	Best	High
Sarikiz Deep	1.3	3.2	7.2	1.0	2.4	5.4
West Alasehir	2.1	5.7	14.7	1.6	4.3	11.0
Total	3.4	9.0	21.9	2.5	6.7	16.4
Note: probabilistic evaluation methods used and rounded to the nearest 0.1 MMstb

RISC has classified estimates of future recovery from the Sarikiz Deep and West Alasehir leads as prospective resources. RISC has advised that prospective resources carry with them a risk that potentially moveable hydrocarbons may not be present and also a risk that commercial development may not proceed. Accordingly, confirmation of discovery in these fields will require the drilling of successful exploration wells.

Economic Assessment and Sarikiz-SPP 1 well

The IER also incorporates RISC's preliminary economic assessment associated with development outcomes for the fields contained in the Licence area. These results are encouraging, however, they are subject to successful work programmes and cost efficient delivery.

Dempsey's near term focus is on designing and costing the first well required as part of the Licence work programme agreed with the GDPA. In this regard, Dempsey has retained the services of NauticAWT, a top tier drilling consulting firm, to design a well based on all known field parameters, including the results from past drilling in the Licence area.

Once this design work is complete, Dempsey in conjunction with Petrako Petrol Dogalgaz Insaat Taahhut Isleri Ve Dis Ticaret Limited Sirketi ("Petrako"), Pertoz's Turkish partner, will approach drilling contractors and service providers in order to define the cost of the proposed well. It is envisaged that the first well will be drilled in the Sarikiz field (where contingent resources have been identified) and be known as Sarikiz-SPP 1. A successful programme in relation to the Sarikiz-SPP1 well will be an important step in demonstrating the commerciality of the Sarikiz field.

Nathan McMahon, Chairman of Dempsey, indicated that he was encouraged by the outcomes from the RISC report. "RISC's analysis and findings have provided the Dempsey board with great confidence in relation to the Sarikiz and Alasehir fields. We are pleased with the contingent and prospective resource outcomes, however, are now focused on the NauticAWT well design as it is an important next step. The Dempsey Board is committed to cost and capital efficient execution for the benefit of Dempsey shareholders. In this regard, we want the appropriate analysis and work to be completed so that Dempsey has every chance of commercial success in developing these oil fields. Furthermore, a recent full, in-country due diligence exercise which included meeting with key government officials, local bodies, drilling companies and seismic groups provided further confidence in the project".

For further information contact: Nathan McMahon

Non-Executive Chairman Email: [email protected] Tel: (08) 9322 6283

Competent Person

The estimates of Contingent Resources and Prospective Resources provided in this announcement are based on, and fairly represents, information and supporting documentation prepared under the supervision of Mr Geoffrey Barker of RISC Operations Pty Ltd ("RISC") in accordance with Petroleum Resource Management System standards, definitions and guidelines. Mr Barker is a partner of RISC and is a qualified person as defined under ASX Listing Rule 5.42. Mr Barker is a member of the Society of Petroleum Engineers and is a qualified petroleum and resources evaluator (QPPRE) as defined by ASX listing rules. Mr Barker has given his consent to the use of the Contingent and Prospective Resources figures in the form and context in which they appear in this presentation

Independent Expert Report
Petroz Ltd's interests in Licence L21A Alasehir & Sarikiz Oil
Fields, Onshore Turkey

December 2015

decisions with confidence

1.		Introduction 1 1
2.		Summary
	2.1. 2.2. 2.3. 2.4.	Overview Resource Summary Development Plans and Forecasts Economic Evaluation
3.		Terms of Reference
4.		Basis of Assessment
	4.1.	Resource Classification
5.		Licence History and Status
6.		Regional Setting
	6.1.	Petroleum System
7.		Contingent Resources
	7.1. 7.2.	Sarikiz Oil Field Alasehir Oil Field
8.		Development Plans and Forecasts
	8.1. 8.2. 8.3.	Production Forecasts Cost Estimates Cost Forecasts
9.		Prospective Resources
	9.1. 9.2. 9.3.	Sarikiz Deep Lead West Alasehir Lead Chance of Success
		10. Economics
	10.1. 10.2. 10.3.	Fiscal Terms Economic parameters Unrisked Valuation
		11. Declarations
	11.1. 11.2. 11.3. 11.4. 11.5. 11.6.	Qualifications ……………………………………………………………………………………………… VALMIN Code Petroleum Resources Management System Independence Limitations Consent
		Bibliography
		Appendix 1: List of terms

List of figures

Figure 2-1: Location Map - Licence L21A
Figure 2-2: Location Map - Sarikiz, Alasehir Oil Fields and Leads
Figure 2-3: Sarikiz Production Forecast Summary
Figure 2-4: Alasehir Production Forecast Summary
Figure 4-1: Resources classification framework
Figure 5-1: Location Map - Licence L21A
Figure 5-2: Location Map L21A - Wells and Seismic Line locations
Figure 6-1: Tectonic Map of western Anatolia with the Alasehir Graben highlighted
Figure 6-2: Simplified Regional, Tectonic Map, showing the Alasehir Graben, the Alasehir supradetachment basin, the Kula volcanic field and the WNW orientated normal and NNE striking oblique, hinge faults. 16
Figure 6-3: SSW-NNE orientated block diagram, depicting the internal structure of the Alasehir supradetached basin, the modern Alasehir graben and the Menderes massif ³
Figure 6-4: Regional Seismic lines 201 (strike) and 204 (dip) located in the Alasehir Graben 17
Figure 6-5: Lithostratigraphy of the Alasehir Graben
Figure 6-6: Play Types - Alasehir Graben ³
Figure 6-7: Alasehir-1 well stratigraphy
Figure 7-1: 2D Seismic Line location Map
Figure 7-2: Seismic Data Quality - Strike Line through Sarikiz-2
Figure 7-3: Alasehir 1/A Checkshot Survey
Figure 7-4: Depth Conversion - Intra Alasehir Time Vs Depth Structure Maps
Figure 7-5: Sarikiz Oil Field - Intra Alasehir Depth Structure Map
Figure 7-6: Dip Line ALV-06-104 - Sarikiz Oil Field
Figure 7-7: Sarikiz-2 - Part of Zone 2 Petrophysical Interpretation
Figure 7-8: Sarikiz-2 - Zone 1 Petrophysical Interpretation
Figure 7-9: Sarikiz-1 DST -2 & 3
Figure 7-10: Alasehir and Sarikiz oilfields - Intra Alasehir Depth Structure Map
Figure 7-11 Sarikiz Single Well Production Forecasts
Figure 7-12: Strike Line IZD-95-205 through Alasehir-1 Oil Discovery
Figure 7-13: Alasehir 1/A Checkshot Survey management management management management and 35
Figure 7-14: Depth Conversion - Intra Alasehir B Time Vs Depth Structure Maps
Figure 7-15: Alasehir Oil Field - Intra Alasehir B Depth Structure Map
Figure 7-16: Alasehir Strike Line through Alasehir-1 Oil Discovery
Figure 7-17: DST-2,-3,-4,-5 Alasehir-1
Figure 7-18 Alasehir Single Well Production Forecasts

Figure 8-1 Sarikiz Production Forecast Summary
Figure 8-2 Alasehir Production Forecast Summary
Figure 8-3: Sarikiz 1C, 2C and 3C Cost Forecasts
Figure 8-4 Alasehir 1C, 2C and 3C Cost Forecasts
Figure 9-1: Intra Alasehir B Depth Structure Map - Sarikiz Deep Lead
Figure 9-2: Line IZD-98-204 - Sarikiz Deep Lead
Figure 9-3: Intra Alasehir B Depth Structure Map - West Alasehir Lead
Figure 9-4: Strike Line through Alasehir 1 well - West Alasehir Lead

1970

List of tables

Table 2-1: L21A Contingent Resources - as at 30 September 2015
Table 2-2: L21A Prospective Resources - as at 30 September 2015
Table 2-3: Field Development Plan Summary (100%)
Table 2-4 Estimated unit well drilling and completion costs US\$ million
Table 2-5 Sarikiz and Alasehir Unrisked NPV (Petroz net 75%)
Table 4-1: Prospective Resources Definition
Table 5-1: Licence Details and Commitment Work Programme
Table 7-1: Sarikiz-2 Net Pay calculation
Table 7-2: Volumetric Inputs for Sarikiz Oil Field
Table 7-3: Contingent Resources - Sarikiz Oil Field
Table 7-4 Sarikiz Well Recovery and Productivity Assumptions
Table 7-5: Volumetric Inputs for Alasehir Oil Field
Table 7-6: Contingent Resources for the Alasehir Oil Field (100%) as at 30 September 2015 39
Table 7-7 Alasehir Well Recovery and Productivity Assumptions
Table 8-1 Field Development Plan Summary
Table 8-2: Summary of Previous Well Drilling Performance
Table 8-3 Estimated unit well drilling and completion costs US\$ million
Table 8-4 Oil Processing Facilities Cost Summary
Table 9-1: Volumetric Inputs for the Sarikiz Deep Lead
Table 9-2: Prospective Resources for the Sarikiz Deep Lead
Table 9-3: Volumetric Inputs for the West Alasehir Lead
Table 9-4: Prospective Resources for the West Alasehir Lead
Table 9-5: Probability of Success - Sarikiz Deep Lead
Table 9-6: Probability of Success - West Alasehir Lead
Table 10-1 Brent Oil Forward Curve
Table 10-2 Sarikiz and Alasehir Unrisked NPV (Petroz net 75%)

COLOR

The Directors Dempsey Minerals Ltd Level 2, 38 Richardson Street West Perth Western Australia, 6005

Dear Sirs.

Independent Expert Report on Petroz Limited's interests in Licence L21A Alasehir & Sarikiz Oil Fields, Onshore Turkey

Introduction $\mathbf{1}$ .

Dempsey Minerals Ltd, ("Dempsey") has appointed RISC Operations Pty Ltd ("RISC") to prepare an independent expert's report on the assets of Petroz Ltd in relation to their interests in Licence L21A Alasehir & Sarikiz Oil Fields, Onshore Turkey.

The document comprises the Independent Expert Report by RISC Operations Pty Ltd ("RISC") to assist the Directors of Dempsey in the evaluation of the Petroz assets. It documents our review of Petroz's petroleum resources and associated development schedules, production and cost forecasts and discounted cash flow of the unrisked contingent resources. We have reviewed the estimates provided by Petroz and made such adjustments that in our judgment were necessary to provide a reasonable assessment and reflect current information.

Petroz has made available to RISC a data set of technical information including geological, geophysical, petrophysical, development, production and operational data and reports. RISC has also had meetings and discussions with Petroz's technical and management personnel. In carrying out this review, RISC has relied on the information received from Petroz and information in the public domain.

To assess reserves and resources, RISC has used the Petroleum Resources Management System published by the Society of Petroleum Engineers / World Petroleum Council / American Association of Petroleum Geologists / Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/APEE) in March 2007 (PRMS).

RISC has carried our evaluation in accordance with the VALMIN Code.

This report does not give and must not be interpreted as giving, an opinion, recommendation or advice on a financial product within the meaning of section 766B of the Corporations Act 2001 or section 12BAB of the Australian Securities and Investments Commission Act 2001. RISC is not operating under an Australian financial services licence in providing this report.

$2.$ Summary

$2.1.$ Overview

The locations of Petroz's petroleum properties are shown in Figure 2-1. L21A contains two discovered oil fields: Sarikiz and Alasehir (Figure 2-2).

Figure 2-1: Location Map - Licence L21A

The Sarikiz and Alasehir oil fields are located in the western part of Licence L21A and covered by a detailed 2D seismic grid Figure 2-2. The fields are contained in combination structural / stratigraphic traps with 3 way closure and updip seal against a basement fault within Early to Middle Miocene clastic reservoirs of the Alasehir Fm. The fields have multiple oil sands that are typically 1 to 5 m in gross thickness.

The Alasehir field was discovered by Alasehir-1 in 1998 which recovered 21 bbls gassy oil from the best of 7 open hole tests. Oil gravity was 31° API.

Five wells have been drilled on the Sarikiz field from 2000-2010. The most recent Sarikiz-2 (2009) well tested approximately 5 m of net oil pay over the interval 1544-1657 m and recovered an average of 75 bopd of 37 API oil with about 50% BS&W.

In addition to the discovered oil pools, significant undiscovered oil potential exists in the West Alasehir and Sarikiz Deep exploration leads.

Figure 2-2: Location Map - Sarikiz, Alasehir Oil Fields and Leads

Petroz plans to twin the Sarikiz-2 well and place it on extended test to confirm the production potential and drive mechanism prior to development commitment.

$2.2.$ Resource Summary

RISC has carried out an independent resource estimate for the two fields. We estimate 2C contingent resources net to Petroz of 6.8 MMstb and a further best estimate of unrisked net prospective resources of 6.7 MMstb (Table 2-1 and Table 2-2).

Field	Gross (100%) MMstb			Net Petroz (75%) MMstb
	1 ^C	2C	3 _C	1C	2C	3 ^C
Sarikiz	1.4	3.1	5.8	1.1	2.3	4.4
Alasehir	2.5	6.0	12.5	1.9	4.5	9.4
Total	3.9	9.1	18.3	3.0	6.8	13.7

Table 2-1: L21A Contingent Resources - as at 30 September 2015

1. Probabilistic evaluation methods have been used.
1. Arithmetic addition has been used to sum the field resource estimates. The arithmetic sum may result in overly conservative estimates in the 1C case and overly optimistic estimates in the 3C case due to portfolio effects.
1. Rounded to the nearest 0.1 MMstb. Totals may not add due to rounding.

We have classified the estimates of future recovery from the Sarikiz and Alasehir fields as contingent resources. Contingent resources carry with them a risk that commercial development may not proceed. In the case of the L21A fields, confirmation of the commerciality of the development is pending encouraging results from the drilling, testing and evaluation of the Sarikiz and Alasehir test wells.

Field		Gross (100%) MMstb			Net Petroz (75%) MMstb
	Low	Best	High	Low	Best	High
Sarikiz Deep	1.3	3.2	7.2	1.0	2.4	5.4
West Alasehir	2.1	5.7	14.7	1.6	4.3	11.0
Total	3.4	9.0	21.9	2.5	6.7	16.4

Table 2-2: L21A Prospective Resources - as at 30 September 2015

1. Probabilistic evaluation methods have been used.
1. Arithmetic addition has been used to sum the field resource estimates. The arithmetic sum may result in overly conservative estimates in the 1C case and overly optimistic estimates in the 3C case due to portfolio effects.
1. Rounded to the nearest 0.1 MMstb. Totals may not add due to rounding.

We have classified the estimates of future recovery from the Sarikiz Deep and West Alasehir leads as prospective resources. Prospective resources carry with them a risk that significant quantities of potentially moveable hydrocarbons may not be present and also a risk that commercial development may not proceed. In the case of the L21A prospective resources, confirmation of discovery will require the drilling of successful exploration wells in each of the leads.

$2.3.$ Development Plans and Forecasts

Petroz has presented a staged development plan for the Sarikiz and Alasehir oil fields. They anticipate drilling a new development well which is a twin of the Sarikiz-2 well in 2016. This well will be produced to temporary leased production facilities to test the feasibility of a larger development. If the results are favorable the wider Sarikiz field will be developed. A similar plan is envisioned for Alasehir with a single appraisal well being drilled in 2018 followed by full field development if the well is successful. A summary of the field development plan well count and costs is shown in Table 2-3.

	Sarikiz			Alasehir
	1C Case	2C Case	3C Case	1C Case	2C Case	3C Case
# of Wells	13	15	18	13	20	26
Peak oil rate (bbl/d)	1,200	2,200	3,800	2.050	3,900	7,000
Contingent Resource (MMstb)	1.4	3.1	5.8	2.5	6.0	12.5
First oil (yr)	2016	2016	2016	2018	2018	2018
Capex US\$ mill	43.9	52.6	67.3	53.4	83	111.3
Average Opex US\$ mill pa	3.7	4.8	6.6	4.4	6.5	9.4

Table 2-3: Field Development Plan Summary (100%)

A key sensitivity is well costs. Petroz have estimated typical development well costs to be US\$2.2 million per well based on a 21 day drill and complete duration and a rig rate of US\$15k/d. The implied average penetration rate based on these assumptions is 80m/d.

We have reviewed the time vs depth curves for the previous wells drilled in the field to understand the likely duration of future development wells. The historical well performance varies from 40 m/day to 60 m/day.

We consider the Petroz proposed US\$2.2 million cost for the initial well to be achievable provided that the 80m/d penetration rate is achievable, all operations go smoothly, and that no problems are encountered. In our experience this is an optimistic view and we would add in some contingency to reflect the potential for delays. If the better penetration rates assumed by Petroz can be achieved, the unit well drilling and completion costs will be reduced by approximately 12% from our estimates (Table 2-4). As a result we anticipate costs for the first well of US\$2.3-2.6 million.

Table 2-4 Estimated unit well drilling and completion costs US\$ million

Field	Average penetration rate 55-60m/d	Average penetration rate 80 _m /d
Sarakiz (1750m TD)	2.6	2.3
Alasehir (2150m TD)	3.1	2.7

The above costs are inclusive of well completion. We understand that well completion and testing mayl be carried out using a separate workover rig, which will be brought to site once the drill rig has demobilized.

The completion cost using the drilling rig is estimated to be \$0.5m, of which \$0.4m is completion equipment and consumables which is common to both operations. Using a workover rig to complete the wells will result in a small potential saving on the order of \$50k/well.

We have adopted the 55-60m/d penetration rate in our base case estimates. However we consider that with a continuous operation, implementation of continuous improvement systems from a cost focused operator could reduce the unit well costs by 30% and have presented this as a sensitivity.

The field development plans are based on vertical development wells drilled from 6 well pad clusters.

Well testing has shown that produced fluids have exhibited high levels of CO2 along with saline formation water. Both of these fluids are highly corrosive and we have assumed that all materials used in the development of these fields will have corrosion resistant coatings or be composed of corrosion resistant alloys.

A summary of the production forecast for each development case is shown in the charts below Figure 2-3 and Figure 2-4. The bars show annual production rate in bbl/d while the lines show cumulative production in MMbbl.

Figure 2-3: Sarikiz Production Forecast Summary

Figure 2-4: Alasehir Production Forecast Summary

$2.4.$ Economic Evaluation

RISC has carried out a discounted cash flow analysis of the contingent resources within the Sarikiz and Alasehir oil fields to demonstrate the economic potential of future development. The net present values have been estimated using a 10% nominal discount factor (NPV10 discounted to 30 Sep 2015) and incorporate economic cut-offs to field production. The net present values shown in Table 2-5 have not been adjusted for technical and commercial risk and market factors and should not be construed as a fair market value.

Net to Petroz (75%)	Economic cut-off	Economic Recovery MMstb	Unrisked NPV10 (US\$ million)	Unit NPV (NPV10 US\$/bbl)
Sarikiz - 3C case	$Jan-27$	4.3	56	13
Sarikiz - 2C case	$Jan-26$	2.2	18	8
Sarikiz - 1C case	$Jan-24$	1.0	-6	-6
Alasehir – 3C case	$Jan-31$	9.3	128	14
Alasehir - 2C case	$Jan-29$	4.4	45	10
Alasehir - 1C case	$Jan-27$	1.8	8	4

Table 2-5 Sarikiz and Alasehir Unrisked NPV (Petroz net 75%)

If a 30% cost reduction in well costs could be achieved, an approximate uplift to the NPV's of 23% for the Sarikiz 2C case and 12% for the Alasehir 2C case would result.

Terms of Reference $3.1$

Petroz has requested that RISC to carry out the following scope of work:

RISC will review the available data on the existing discovery wells and prospects. The Technical review will rely on data provided by Petroz. It will also include any development plans Petroz and its partners might have in order to verify the contingent resources.

The following list outlines the work scope for the independent review:

Review of the Permit status, exploration history and development plans of the L21A block $\blacksquare$
×. Describe the petroleum systems and exploration play types for the exploration block
Review the primary and secondary reservoir targets and their petrophysical parameters ×
Review the current seismic mapping, well ties and depth conversion for an auditable trail to current n depth maps
Review and adjust depth maps, hydrocarbon contacts and prospective spill points
Estimate 1C, 2C and 3C contingent resources for each discovered accumulation п
Estimate prospective resources for remaining prospects and probability of success
Prepare production forecasts and associated cost (Capex and Opex) profiles for 1C and 2C scenarios ٠ including development drilling schedule for the oil discoveries
Carry out an economic evaluation to evaluate development economics and economic cut-off and $\blacksquare$ estimate the net present value of the production and planned production to estimate the value of the assets
Provide a written Independent Expert Report compliant with ASX listing rules

4. Basis of Assessment

The data and information used in the preparation of this report were provided by Petroz and supplemented by public domain information. RISC has relied upon the information provided and has undertaken the evaluation on the basis of a review of existing interpretations and assessments as supplied, making adjustments that in our judgment were necessary. We believe we have been provided with all relevant information. The data reviewed included a seismic workstation project, well data and interpretative reports. Our assessment included detailed discussion with Petroz staff involved in the assets reviewed.

Our approach has been to conduct our own 2D seismic interpretation of the data in the licence and perform a petrophysical interpretation of the Sarakiz-2 and 3 wells for reservoir parameters. We undertook our own volumetric assessment to derive resources and an estimate of the production forecasts and associated cost (Capex and Opex) profiles including development drilling schedule for the oil discoveries. RISC also created an economic model of the fields to evaluate development economics and economic cut-offs.

We have carried out our evaluation in accordance with the VALMIN code¹.

Unless otherwise stated, all costs and values are in gross US\$ real terms with a reference date of 1 January 2015. Production is reported in gross terms unless otherwise stated with a reference date of 30 September 2015.

Resource Classification $4.1.$

RISC has used the internationally recognised Petroleum Resources Management System (PRMS)² to define resource classification and volumes. The classification of resources is shown in Figure 4-1.

Figure 4-1: Resources classification framework

Each project is classified according to its maturity or status (broadly corresponding to its chance of commerciality) using three main classes, with the option to subdivide further using subclasses. The three classes are Reserves, Contingent Resources, and Prospective Resources.

^1 Code for the Technical Assessment and Valuation of Mineral and Petroleum Assets and Securities for Independent Expert Reports 2005 Edition

^2 SPE/WPC/AAPG/SPEE 2007 Petroleum Resources Management System

Petroz have Contingent Resources for the Sarikiz and Alasehir Oil Fields and Prospective Resources for the Sarikiz Deep Lead and the West Alasehir Lead according to this classification.

For projects that satisfy the requirements for Contingent Resources the three estimates of the recoverable sales quantities are designated are 1C, 2C, and 3C, while the terms low estimate, best estimate, and high estimate are used for Prospective Resources.

Under the PRMS guidelines, the range of uncertainty in potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution derived from the probabilistic simulation of input variables. RISC has calculated resource volumes probabilistically.

The PRMS guidelines indicate that when the range of uncertainty is represented by a probability distribution, a 1C, 2C, and 3C estimate shall be provided such that:

There should be at least a 90% probability (P90) that the quantities actually recovered equal or exceed $\blacksquare$ the low estimate
There should be at least a 50% probability (P50) that the quantities actually recovered equal or exceed the best estimate
There should be at least a 10% probability (P10) that the quantities actually recovered equal or exceed the high estimate.

The guidelines indicate that when the range of uncertainty is represented by a probability distribution, a low, best, and high estimate shall be provided such that:

There should be at least a 90% probability (P90) that the quantities actually recovered equal or exceed the low estimate
There should be at least a 50% probability (P50) that the quantities actually recovered equal or exceed the best estimate
There should be at least a 10% probability (P10) that the quantities actually recovered equal or exceed the high estimate

Prospective Resources can be subdivided into Prospect, Lead or Play. The definitions from the PRMS guidelines are given in Table 4-1.

Table 4-1: Prospective Resources Definition

Prospective Resources	Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.	Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavity on analog developments in the earlier phases of exploration.
Prospect	A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.	Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.
Lead	A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect.	Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios.
Play	A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects.	Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

$4.1.1.$ Chance of Discovery

Prospective Resources have both an associated chance of discovery and an additional chance of commercial development. By implication, not all discovered volumes are necessarily commercial. For the present study when evaluating the prospective resources RISC has restricted its statement to a view of the chance of discovery - equivalent to the geological chance of success.

RISC uses the geological chance of success (POSg) to reflect the chance of encountering a significant volume of recoverable hydrocarbons. In this context, 'significant' implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place volume demonstrated by the well(s) and for evaluating the potential for economic recovery (PRMS).

Note that there is an additional chance to reach a specific volume, such as a commercial volume.

Risking methodology specific to the leads is discussed further in the report.

Licence History and Status 5.

$5.1.1.$ Licence Status

The Alasehir Licence L21Ais located in the Manisa Provence, Western Turkey Figure 5-1. The license was jointly awarded to Petroz Ltd (75%) and Petrako (25%) by the Turkish authorities (GDPA) on 25 August, 2015 (Effective Date).

The initial term of the permit is five (5) years commencing on the Effective Date, after which time Petroz may exit or elect to enter into the first extension period of a further two (2) years. Following the first extension period, Petroz may again elect to exit or continue into the second extension period of two (2) years. The exploration licence can be handed back at the end of each year without penalty. Production can continue under a production licence if the exploration licence is handed back and the Production Licence is for 20 Years plus extensions for the life of the field.

Figure 5-1: Location Map - Licence L21A

The Licence and commitment work programme details are given in Table 5-1. The licence is currently in Year-1 of the 5 year work programme. The key element for the Year 1 work programme is the drilling of Sarakiz-2A, a twin of the Sarakiz-2 oil discovery.

Asset	Operator	Interest	Status	Licence Expiry Date	Licence Area	Work Commitments
Alasehir License L21A	Petrako	Petroz Ltd 75% Petrako 25%	Exploration Licence	26 ^th August 2020 (with two 2 yr extensions)	$606 \ km2$	well 1-drill 1 Year $(US$3.65m)$ , Year 2-3D seismic survey, drill 1 well, surface facility $(US$6.4m)$ , Year 3-drill 1 well (US\$3.5m) Year 4-drill 3 wells (US\$9.0m) Year 3-drill 3 wells (US\$9.0m) Total US\$31.65m

			Table 5-1: Licence Details and Commitment Work Programme
--	--	--	----------------------------------------------------------

Note that the above costs are indicative only.

$5.1.2.$ Exploration History

The Alasehir Basin is a semi-mature hydrocarbon exploration and production area in Western Turkey.

The Turkish National Oil Company TPAO were the original operator of Block 3846 (the current licence L21A) and recorded 15 lines of 2D seismic with a dynamite source (total 263.5km) in 1995 and 1998 in support for their future drilling program Figure 5-2.

Figure 5-2: Location Map L21A - Wells and Seismic Line locations

The 2D seismic grid provided only sparse seismic control for the location of the wells and consequently a number of the wells were either drilled down dip from the crest of the structure or outside structural closure.

TPAO drilled 4 exploration wells in the period 1998 to 2001:

Alasehir-1 (1998), drilled to T.D. 2,524m: recovered 21 bbls gassy oil
Sarikiz-1 (2000), drilled to T.D. 2,120m: recovered gassy oil. Sarikiz-1A twin (T.D. 1,753m) flowed 60 bbls ×. oil
East (Dogu) Sarikiz-1 (2001), drilled to T.D. 2,450m: oily mud п

TPAO's withdrawal from the concession in 2002 due to operational difficulties of working in a geothermal basin with high sedimentary temperatures and the presence of CO2 plus the low oil prices (US\$20-30/bbl) and poor drilling practices. The lack of a clear commercial result and with so many other areas to explore the company decided to relinquish the acreage.

A Joint Venture of Extrem Energy (Extrem) & Petrako acquired and explored the acreage from 2004 to 2013. Extrem recorded 132kms of 2D vibroseis data and drilled 2 wells:

Sarikiz-2 (2008), drilled to T.D. 1,847m: flowed oil at an average rate of 75 bbl/day with 50% BS&W. n Sarikiz-2 placed on production but was abandoned in 2009 due to downhole equipment failure.
Sarikiz-3 (2010), drilled to T.D. 2,027m: dry hole ٠

On the 25th August, 2015 the license was jointly awarded to Petroz Ltd (75%) and Petrako (25%) by the Turkish authorities (GDPA).

Regional Setting 6.

$6.1.$ Petroleum System

$6.1.1.$ Structure of the Alasehir Basin

The E-W-trending Alasehir basin, exposed on the uplifted southern shoulder of the modern Alasehir-Gediz graben, is a approximately 10-km-wide 140-km long, asymmetric curvilinear, paleo-depocenter with the sedimentological and structural features characteristic of supradetachment basins (Friedmann and Burbank, 1995; Oner and Dilek, 2011; Sözbilir, 2001) Figure 6-1. Its orientation changes from mainly W-E in its western end to a NW-SE direction in its eastern termination.

Figure 6-1: Tectonic Map of western Anatolia with the Alasehir Graben highlighted

The thickness of the basin strata laterally changes from west to east, ranging between 2000 and 3000 m. It developed above the N-dipping, low-angle Alasehir detachment zone in the Central Menderes Massif between the early Miocene and the Pleistocene (Oner and Dilek, 2011, and references therein). The Alaşehir detachment fault (ADF) separates the high-grade metamorphic rocks of the Menderes Massif and the synextensional Salihli granitoid pluton in the footwall from the lower Miocene-Pleistocene sedimentary strata in the hanging wall.

The Plio-Quaternary alluvial fan and fluvial sediments of the modern Alasehir graben are faulted against the supradetachment basin strata along a N-dipping and seismically active, high-angle normal fault (Figure 6-2 and Figure 6-3).

Figure 6-2: Simplified Regional, Tectonic Map, showing the Alasehir Graben, the Alasehir supradetachment basin, the Kula volcanic field and the WNW orientated normal and NNE striking oblique, hinge faults³.

³ Catlos et al., 2010, 2011; Dilek et al., 2009; Emre, 1996; Emre and Sozbilir, 1995; Koçyiğit et al., 1999; Lips et al, 2001; Sözbilir, 2001

Figure 6-3: SSW-NNE orientated block diagram, depicting the internal structure of the Alasehir supradetached basin, the modern Alasehir graben and the Menderes massif³.

Figure 6-4 shows structural cross-sections of the Alasehir-Gediz Graben based on the geological interpretations of seismic Lines 201 (along the graben axis) and 204 (perpendicular to the graben axis). In both cross sections the internal structure of the graben is strongly controlled by the NNE-SSW- and E-Woriented fault systems. The NNE-SSW - running faults are mostly sub-vertical with upward-branching splays, and locally offset the formation boundaries for 10s of meters. These faults coincide with the transfer (or cross) faults mapped at the surface on the northern and southern shoulders of the graben where lateral displacements of several km within and between the lithological units have been observed.

Figure 6-4: Regional Seismic lines 201 (strike) and 204 (dip) located in the Alasehir Graben

It is inferred that these NNE-SSW-oriented transfer faults within the graben fill produced local positive flower structures and uplift as well as negative flower structures and subsidence, and that they affected the thicknesses of sediment accumulation laterally in the depocenter. This observation suggests that the formation of the sedimentological units was contemporaneous with hinge-faulting across the depocenter. The metamorphic basement beneath the sedimentary strata is also locally uplifted along these transfer faults.

The formation of the Alasehir-Gediz Graben is a very late-stage phenomenon (since 2.5 Ma) in the extensional tectonic evolution of the Menderes Metamorphic Massif.

$6.1.2.$ Stratigraphy of the Alasehir Basin

The basinal strata consist mainly of clastic rocks deposited in lacustrine, alluvial, fluvial and alluvial-fan depositional environments and ranges in age from Early Miocene to Plio-Pleistocene Figure 6-5.

Figure 6-5: Lithostratigraphy of the Alasehir Graben

Alasehir Formation

The oldest stratigraphic unit is the Alasehir Formation, which rests directly on the low-angle detachment surface, and consists of pebble- to cobble-sized conglomerate at the base, fining upwards into thinly-bedded or laminated sandstone, siltstone and shale. Sandstone and organic-rich shale occur as well-sorted, wellbedded sections in a silty or muddy matrix. These clastic units are overlain conformably by pebble conglomerate, muddy sandstone, clayey-limestone, and dolomitic limestone with red-coloured claystone and tuffaceous interlayers. The total thickness of the Alasehir Formation varies between 628 meters (Sarikiz-

1 Well) and 904 meters (Alasehir-1 Well). The depositional setting of the Alasehir Formation has been inferred as fluvial plain and lake with alluvial fan and delta facies. The palynological data suggest Lower Miocene (20-14 Ma) ages of the Alasehir Formation.

Adala Formation

The Adala Formation rests conformably on the Alasehir Formation, but locally it may be juxtaposed against the Menderes Massif metamorphic rocks along the Alasehir detachment surface where the Alasehir Formation is missing. It starts at the bottom with poorly sorted conglomerate with a sand to silt size matrix, and grade upwards into tabular to cross-bedded sandstone with muddy matrix and local limestone lenses. The entire formation has a distinctive red colour, and corresponds to the Çaltilik Formation of Yilmaz et al. (2000). Its overall thickness at the surface to the south is about 400 meters, and is estimated to be between 120 and 250 meters within the graben fill as constrained by the well log data. The depositional setting of the Adala Formation (and its exposed equivalents) is interpreted as fluvial plain, alluvial-fan and small lacustrine environment (Ciftçi and Bozkurt, 2009; Oner and Dilek, 2011). The palynological data from its lower part suggest middle to upper Miocene ages for the Adala Formation (Ediger et al., 1996; Seyitoglu and Scott, 1996).

Hamamdere Formation

The Hamamdere Formation conformably overlies the Adala Formation and consists of alternating layers of light-red and gray-colored conglomerate, sandstone and mudstone. The thickness of the Hamamdere Formation laterally varies significantly both in the exposed outcrops and within the graben fill. Its maximum thickness in the exposed Alasehir supradetachment basin strata to the south is approximately 510 meters. It is about 250 meters in Alasehir-1 and 770 meters in Sarikiz-1 Wells. The inferred depositional setting of the Hamamdere Formation transitions from an alluvial-fan system (conglomerates) in the south to a fluvial plain (sandstone-mudstone) in the north. Based on the occurrence of Upper Miocene freshwater gastropod fauna in its stratigraphic equivalent of the Gobekli Formation, the age of Hamamdere is constrained as Upper Miocene-Lower Pliocene (Emre, 1996; Purvis and Robertson, 2005).

Kaletepe Formation

The Kaletepe Formation rests unconformably over Hamamdere and consists mainly of moderately to poorly consolidated, polygenic conglomerate, sandstone and mudstone (Yazman et al., 1998; Demirtasli, 2004; Ciftci and Bozkurt, 2009; Oner and Dilek, 2011). The upper fine-grained sandstone-mudstone layers are intercalated with lignite and bituminous coal horizons and medium-to thick-bedded organic clay layers (Oner and Dilek, 2011). The minimum thickness of the exposed Kaletepe Formation to the south is approximately 250 meters, whereas it's observed thickness in Alasehir-1 and Sarikiz-1 Wells within the graben is 484 m and 418 m, respectively. The occurrence of plant fragments, pollen and gastropod fossils from the fine-grained midsections of its stratigraphic equivalent Yenipazar Formation suggest Upper Pliocene-Pleistocene ages for the Kaletepe Formation (Sarica, 2000).

Quaternary alluvium

The Quaternary alluvium unit within the Alasehir-Gediz Graben consists of coalesced alluvial fan deposits close to the graben boundaries to the north and south, and finer grained clastic sediments (sand, silt and mud) of the axial fluvial system in the graben center. The axial fluvial sediments are the products of the meandering channel system of the modern Gediz River. The thickness of the Quaternary alluvium varies

laterally along and across the graben. It is observed as approximately 270 meters in Alasehir-1 and 328 meters in Sarikiz-1 Wells.

$6.1.3.$ Trap

Trapping mechanisms are predominantly hanging wall fault dependent closures, sealed updip laterally against intra-formational shales or basement in the foot-wall, with dip closure on other sides. The NNE-SSWoriented, extension-parallel transfer (cross) faults crosscut the graben-fill and the basin strata, and locally displace them for tens of meters. These faults display positive and negative flower structures associated with discrete zones of basement uplift and subsidence across which lithological units have significant lateral and vertical variations in their thickness. It is these locations that the traps are likely to occur.

The Sarikiz and Alasehir Oil Fields are an example of a typical play type for the Alasehir Graben with the Sarikiz Field located on the southern side of the graben and the Alasehir on the northern side Figure 6-6.

Figure 6-6: Play Types - Alasehir Graben³

The primary play types are structural/stratigraphic with the primary reservoir in the Alasehir Formation in a 3 way structural closure with the updip seal of the reservoir against the basement or a pinchout of the reservoir to form a stratigraphic trap. The intervening shales provide the source rocks and the top seals.

In the two discoveries to date hydrocarbon columns range up to several hundred meters, with net pay seen in wells between 1m and 5.2m in the Sarikiz-2 well.

$6.1.4.$ Source

Lacustrine source rocks are widespread in the Alasehir Basin and the black lacustrine shales have formed an excellent oil source (TOC: 4-5%) from the Alasehir Formation. The thickness of the clastic section is over 3,000m in the centre of the basin and generation of hydrocarbon is likely to be extensive due to a high geothermal gradient (42°/km).

The location of the Sarikiz and Alasehir Oil Fields on a basement high allows easy migration from the adjacent source kitchens in the structural highs. The faulting of the section also allows for vertical migration into the shallower section via the faults.

The oil produced at Sarikiz and Alasehir ranges in gravity from 27° API to 37° API and has a moderate wax content.

$6.1.5.$ Reservoir

The success of the Sarikiz and Alasehir oil discoveries proves the viability of the Alasehir Formation, clastic reservoirs with gross thickness of the section from 500m to over 1,000m. The reservoirs have been deposited in a fluvial to lacustrine environment and the wells drilled within the licence show thin bedded reservoirs of less than 20m thickness and a net to gross of 15% to 50% (Figure 6-7). The porosity of the sands in Sarakiz-2 ranges from 10% to 16% with low to moderate permeability from 3mD to 50mD.

Figure 6-7: Alasehir-1 well stratigraphy

6.1.6. Seal

The elements for a successful hydrocarbon play are present in the Alasehir Basin, but the critical factor is in finding a widespread sealing facies at an appropriate level. Shales interbedded with late rift phase fluviodeltaics tend to be thin and discontinuous. This is a common characteristic of rifts with no or poorly developed overlying thermal sag basins. The illustration provided above from the Alasehir well illustrates that sealing (top seal) is necessarily intraformational. Nevertheless, the Alasehir and Sarikiz oil discoveries have shown that this is clearly a proven mechanism.

Contingent Resources $7.$

$7.1.$ Sarikiz Oil Field

The Sarikiz Oil Field is located in the western part of Licence L21A and covered by a 2D seismic grid (Figure 7-1). The field is a structural / stratigraphic trap with 3 way closure and updip seal against a basement fault within Early to Middle Miocene clastic reservoirs of the Alasehir Fm.

The field has been evaluated by the following 5 wells:

Sarikiz-1 (2000), Sarikiz-1A (2000), Dogu Sarikiz-1 (2001), Sarikiz-2 (2008) and Sarikiz-3(2010)

Figure 7-1: 2D Seismic Line location Map

$7.1.1.$ Seismic Interpretation

The Sarikiz Oil Field was mapped by RISC across multiple 2D seismic lines with a dip line spacing of 600m and a strike line spacing of 800m to form a detailed seismic coverage. The 2D seismic lines provide adequate coverage to define the major faults, however, a comprehensive 3D seismic survey is required to define the complex faulting across the field. The Intra Alasehir (Cyan) horizon is the key event for the evaluation of the oil bearing reservoirs over the Sarikiz Oil Field.

In general the seismic data quality is fair to good at the Alasehir Fm reservoir target level Figure 7-2.

Figure 7-2: Seismic Data Quality - Strike Line through Sarikiz-2

The well calibration for the seismic interpretation is poor with only the Alasehir-1 well checkshot survey as the time / depth data for the licence area.

The following seismic events were mapped across the Sarikiz Field (Figure 7-2):

Intra Hamam (Red): shallow event with good reliability and helpful for horizon flattening for the deeper reservoir targets.
Top Alasehir (Green): Top Alasehir Fm in Sarikiz-2 only as it is very difficult to correlate the Top Alasehir Fm in the other wells due to lack of log or lithology character. This seismic event shows fair to good reliability across the study area.
Intra Alasehir (Cyan): Intra Alasehir Fm sandstone in Sarikiz-2 close to the oil sands. This event is also very difficult to correlate in the other wells due to lack of log or lithology character. This seismic event shows fair to good reliability across the study area.

$7.1.2.$ Depth Conversion

The Time structure maps have been depth converted using the Alasehir-1 time/depth function from the well the formulae: function has checkshot $7-3$ ). The depth conversion survey (Figure Depth+366.13t²+779.22t+11.36

Figure 7-3: Alasehir 1/A Checkshot Survey

A comparison of the Intra Alasehir Fm time structure map to the depth structure map shows almost identical features with very little distortion going from time to depth (Figure 7-4).

Figure 7-4: Depth Conversion - Intra Alasehir Time Vs Depth Structure Maps

$7.1.3.$ Mapping

The Intra Alasehir (Cyan) horizon depth structure map shows the field to be located on a structural high between two regional lows and therefore forms a focus for oil migration from the adjacent hydrocarbon kitchens (Figure 7-5).

Figure 7-5: Sarikiz Oil Field - Intra Alasehir Depth Structure Map

The field is a structural / stratigraphic trap with 3 way closure and updip seal against a basement fault within Early to Middle Miocene clastic reservoirs of the Alasehir Fm Figure 7-5 & Figure 7-6 (Line location in Figure 7-5). The (P90) area of the field is the lowest closing contour for the structure with a value of 1,380 mss which is 10m down dip from the Sarikiz-2 oil well and updip from Sarikiz-3 and Dogu Sarikiz-1. The Sarikiz-1 oil well is updip from Sarikiz-2 and within structural closure. The well produced 60 bbl of oil on DST. The relief

on the field is 470m with considerable updip potential as all the wells have been drilled down dip from the crest and just above or below the structural closure.

We are unable to determine an oil / water contact for any of the sands in the field due to the lack of data in the log interpretation or the DST test data so we have assumed that the lowest closing contour is the P90 case for the contact.

Figure 7-6: Dip Line ALV-06-104 - Sarikiz Oil Field

$7.1.4.$ RISC Petrophysical Interpretation

RISC conducted a conventional deterministic log analysis on Sarikiz-2 and 3 only as these wells are the only wells with a near complete log set (Figure 7-7). The Alasehir 'reservoir' appears to consist of a large number of stacked sands in a background of silt and shale. The Alasehir Fm was split into 4 zones averaging 100m thick.

Sands can be oil, gas or water bearing and the fluid type in one sand gives no indication of the fluid type in the next shallowest sand. Individual sands are typically 1-2m thick and so just resolvable however, Sw may be over-estimated because of inherently low resolution of the resistivity log.

Well tests generally produce some oil but this can be a small fraction of the total.

Figure 7-7: Sarikiz-2 - Part of Zone 2 Petrophysical Interpretation

Log analysis may agree on the presence of oil or disagree with all the following combinations (Figure 7-8):

Log analysis says oil, DST produced oil (or gas)
Log analysis says water, DST flowed almost entirely water
Log analysis says water, DST flowed some oil
Log analysis says oil, DST flowed almost entirely water

Figure 7-8: Sarikiz-2 - Zone 1 Petrophysical Interpretation

The petrophysical analysis completed by RISC for the Sarakiz-2 well has calculated a range of 1 to 5.2m net pay for the individual sands and a total net pay of 11.7m for the well (Table 7-1). This however, is not the only plausible petrophysical result and alternative interpretations carried out by Petroz calculate a more optimistic net pay and should also be considered as viable.

		Table 7-1: Sarikiz-2 Net Pay calculation

	lSarikiz-2: Alasehir
Zone	Top(m)		Base $(m)$ Gross $(m)$	Net(m)	N/G	PHIT (v/v)	SWT (v/v)	Pay (m)	PHIT (v/v)	SWT (v/v)
	1430.1	1510.0	79.9	47.1	0.59	0.159	0.92		0.2	0.7
2	1510.0	1674.9	164.9	32.9	0.20	0.161	0.83	5.2	0.18	0.6
з	1674.9	1720.0	45.1	11.7	0.26	0.155	0.86	1.1	0.19	0.7
$\overline{4}$	1720.0	1825.0	105.0	16.2	0.15	0.157	0.76	4.4	0.19	0.6
Cut-offs: poro >		0.12
	Vsh <	0.5

$7.1.5.$ Well Test Results

The following are summary DST results from the Sarikiz Oil Field;

Sarikiz-1 (2000): Five (5) open hole DST's were carried out. The best two tests were from intervals 1,685-1,710m and 1,713-1,735m, recovering gassy oil from the drill pipe of 34° and 37° API gravity respectively (Figure 7-9). Associated gas from the deeper test had a composition of 68% CO2, 10% N2 and 21% C1-C4. Only a small part of a thick sequence of inter-bedded oil sands and shale was tested.

At this stage in the drilling of the well, ongoing testing was stopped for operational reasons. During operations to increase BOP size from 3,000 - 5,000 psi, the well suffered an uncontrolled blow-out of oil, gas and mud, which necessitated setting cement and abandoning the well.

Figure 7-9: Sarikiz-1 DST -2 & 3

Sarikiz-1A twin (T.D. 1,753m) was spudded 6 months later 50m from Sarikiz-1. A cased hole commingled DST over the intervals 1,735-1,742m, 1,710-1,726m and 1,682-1,702m flowed 60 bbls oil and 6.5 bbls water/mud/oil mix over a 34 hour period (i.e. a normalized rate of 42 bopd).

Sarikiz-2 (2008), Production testing (2009) was subsequently carried out over 10 perforated intervals in the Alasehir Formation. The best 4 intervals from 1544-1657m were combined and flowed naturally for 6 days at an average flow rate 150 bbl/day (50% high-viscosity brown oil and 50% salty water @ 11-13,000 ppm Cl).

A total of 770 bbl oil was produced of 24°-37° API gravity.

At the completion of tests, a bridge plug was set to allow for future production. A screw pump was installed to increase production, but broke down. Sarikiz-2 was abandoned in 2009 due to downhole equipment failure, which caused the loss of the hole.

$7.1.6.$ Volumetrics

$7.1.6.1.$ Approach

We used a probabilistic method using the industry-standard REP software to combine ranges of input parameters to derive distributions of contingent resources.

$7.1.6.2.$ Gross Rock Volume

Area and net pay

RISC has adopted a net pay and area approach to calculate the gross rock volume for the Sarikiz Oil Field. This approach was based on the relatively thin nature of the oil sands, the occurrence of multiple oil sands and the stratigraphic nature of the trap. The areas have been calculated from the Intra Alasehir Depth Structure Map with the P90 (4 km²) as the lowest closing contour for the structure with a value of 1,380 mss and 10m down dip from the Sarakiz-2 well at 1,370mss. A net pay range of 7.5m (P90), to 12.5m (P10) was used to calculate the GRV.

$7.1.6.3.$ Reservoir and Fluid Parameters

There has been no appreciable production in the basin, although a number of DST's have been performed on Sarikiz-2 which was documented as flowing at approximately 75 bopd with 50% BS&W. Depending on assumed pay and fluid parameters, permeability can be estimated to be anywhere from 3 to 50 mD. A map showing the test results and locations are provided in Figure 7-10.

Figure 7-10: Alasehir and Sarikiz oilfields - Intra Alasehir Depth Structure Map

A log derived permeability of 188 md was reported for Sarikiz-2, but discounted by RISC based on the reported production rate of 150 bfpd (i.e. proxy modeling suggested that a reservoir permeability of 188 md would generate much higher production rates). Furthermore, log derived permeability is heavily dependent upon basic log quality, shale/silt/sand content, irreducible water saturation estimates, and other parameters not well known. Qualitatively, many of the DST's performed vertically throughout the Sarikiz-2 well had slow rate of pressure buildup during shut-in periods⁴ which could be due to formation damage and/or low permeability.

The fluid samples showed oil API's of 24.3 to 36.8 API, which is generally considered to be light oil. "Gassy" oil was reported for a number of these tests; however, detailed fluid analyses or reports describing viscosity, solution gas, relative permeability and saturation pressure were not provided.

The completion report for Sarikiz-2 indicated a shut-in bottomhole pressure of 1800 psia (12,400 kPaa)⁵, but suggested that this value may be pessimistic given the apparent slow rate of buildup⁶. This would suggest an apparent pressure gradient as low as 7.8 kPa/m, but could potentially be 9.8 kPa/m or higher.

^4 Sarikiz-2 Exploration Report: Completion Report. July 2009.

^5 Sarikiz-2 Exploration Report: Completion Report. July 2009.

^6 RISC was not able to verify the pressure interpretation.

$7.1.6.4.$ Recovery Factor

The recovery factor for Sarikiz Oil field was estimated from analogue data using the Sumatran Talang Akar Formation (TAF) as an analogue. The TAF formation is a stacked reservoir fluvial system with porosity and thicknesses comparable to the Alasehir reservoir. Although the overall net to gross of the TAF is generally higher than that seen in the Alasehir reservoir, there are sections with lower NTG and reservoir quality similar to that seen in the Alasehir-1 well. In addition, the oil API is also comparable and it is a complex petroleum system with oil, gas and water fill in the individual sands which are not in communication. Typical recovery factors range from 10-30% which we have adopted for this report.

$7.1.6.5.$ Summary of Volumetric Input Parameters

The following Table 7-2 is a summary of the area and net pay thickness values plus the reservoir input parameters form the RISC petrophysical interpretation for the Sarikiz Oil Field.

Name	Unit	Shape	Min	P ₉₀	P ₅₀	P10	Max	Mode	Mean	Edit
Area	km2	Lognor	3.23	4.00	4.69	5.50	6.81	4.62	4.73	1999.
Thickness	$\mathbf{m}$	Beta	5.00	7.47	9.98	12.5	15.0	10.0	10.0	337
Shape factor	%	Single	100	100	100	100	100	100	100	$***$
Deg. of fill	%	Single	100	100	100	100	100	100	100	4,611
Net-to-gross	%	Single	100	100	100	100	100	100	100
Porosity	%	Beta	12.1	14.0	16.0	18.0	19.9	16.0	16.0
Sw	%	Beta	40.0	50.7	58.7	65.4	70.0	60.0	58.3	$\overline{111}$
FVF (Bo)	rb/stb	Beta	0.865	1.00	1.15	1.30	1.45	1.15	1.15	$\cdots$
Oil rec fac	℁	Beta	3.00	9.39	19.0	30.9	47.0	17.0	19.7	$\mathcal{L}_{\text{int}}$

Table 7-2: Volumetric Inputs for Sarikiz Oil Field

$7.1.6.6.$ Contingent Resources

The estimate of the contingent resources for the Sarikiz Oil Field is given in Table 7-3.

Table 7-3: Contingent Resources - Sarikiz Oil Field

Contingent Oil Resources (MMstb)
	Equity	1 ^C	2C	3 ^C
Sarikiz Oil Field	100%	1.41	3.1	5.82
Petroz Ltd	75%	1.06	2.33	4.37
Petrako	25%	0.35	0.78	1.45

$7.1.7.$ Well Spacing and Recovery

We have adopted an 80 acre spacing with the following initial productivity and recovery parameters for the Sarikiz area. Production forecasts were generated by applying a conventional decline to an estimated range of suitable initial oil rates, and recoveries. A thorough review of recoveries from the quoted TAF analogues (in the public domain) suggested per well oil recovery of 100 to 351 Mstb/well, for the assumed well spacing

of 80 Acres. Assuming exponential decline, the forecasts per well are shown in Figure 7-11. A tabulation of well numbers and recovery is also given in Table 7-4. Initial oil rate was prorated for both net pay and wateroil cut to the test results from Sarikiz -2.

Sarikiz	80 acre spacing
Conf. Level	Area	STOIIP	EUR	RF	Wells	EUR/well	Thickness	ΙP
	km ₂	MMstb	MMstb	%	#	Mstb	m	stb/d
P90	4.0	11.3	1.4	12%	13.0	108	8	120
P50	4.7	16.7	3.1	19%	15.0	207	10	225
P ₁₀	5.5	24.3	5.8	24%	18.0	322	12	350

	Table 7-4 Sarikiz Well Recovery and Productivity Assumptions

Figure 7-11 Sarikiz Single Well Production Forecasts

$7.2.$ Alasehir Oil Field

$7.2.1.$ Seismic Interpretation

The Alasehir Oil Field was mapped by RISC across multiple 2D seismic lines with a dip line spacing of 600m and a strike line spacing of 800m to form a detailed seismic coverage. The 2D seismic lines provide adequate

coverage to define the major faults, however, a comprehensive 3D seismic survey is required to define the complex faulting across the field. The Intra Alasehir B (Purple) horizon is the key event for the evaluation of the oil bearing reservoirs over the Alasehir Oil Field.

In general the seismic data quality is fair to good at the Alasehir Fm reservoir target level Intra Alasehir B Horizon Figure 7-12.

Figure 7-12: Strike Line IZD-95-205 through Alasehir-1 Oil Discovery

The well calibration for the seismic interpretation is poor with only the Alasehir-1 well checkshot survey as the time / depth data for the licence area.

The following seismic events were mapped across the Alasehir Field:

Intra Hamam (Red): shallow event with good reliability and helpful for horizon flattening for the deeper ٠ reservoir targets.
Intra Alasehir (Cyan): Intra Alasehir Fm sandstone in Sarikiz-2 close to the oil sands. This event is also very difficult to correlate in the other wells due to lack of log or lithology character. This seismic event shows fair to good reliability across the study area.
Intra Alasehir B (Purple): Intra Alasehir Fm sandstone in Alasehir-1 close to the oil sands. This event is also very difficult to correlate in the other wells due to lack of log or lithology character. This seismic event shows fair to good reliability across the study area.

$7.2.2.$ Depth Conversion

The Time structure maps have been depth converted using the Alasehir-1 time/depth function from the well The conversion function has the formulae: depth checkshot survey Figure $7-13.$ Depth+366.13t2 +779.22t+11.36

Figure 7-13: Alasehir 1/A Checkshot Survey

A comparison of the Intra Alasehir B time structure map to the depth structure map shows almost identical features with very little distortion going from time to depth Figure 7-14.

Figure 7-14: Depth Conversion - Intra Alasehir B Time Vs Depth Structure Maps

$7.2.3.$ Mapping

The Intra Alasehir B (Purple) horizon depth structure map shows the field to be located on a structural high up-dip from two regional lows and therefore forms a focus for oil migration from the adjacent hydrocarbon kitchens Figure 7-15.

Figure 7-15: Alasehir Oil Field - Intra Alasehir B Depth Structure Map

Figure 7-16: Alasehir Strike Line through Alasehir-1 Oil Discovery

The relief on the field is 200m to the P90 contour level with considerable updip potential as the well was drilled down dip from the crest well above the structural closure at 2,220m.

We are unable to determine an oil / water contact for any of the sands in the field due to the lack of data in the log interpretation or the DST test data so we have assumed that the closing contour 1,960 mss as the P90 case for the contact.

In support of our interpretation a geothermal well, located 650m SSE from Alasehir-1, recovered oil and water from an open hole DST conducted between 2,000 - 3,300m.

$7.2.4.$ Well Test Results

Alasehir-1 (1998), drilled to T.D. 2,524m, recovered 21 bbls gassy oil from the best of 7 open hole DST's. Oil gravity was 31° API, but the wet gas included 72% CO2.

A subsequent cased hole test, after acidizing and swabbing, recovered only oil-cut water. There was less fluid recovered from the test than was injected into the formation and it is likely that the tested interval was not completely isolated, with water encroachment from other zones. The integrity of the casing cement is unknown as CBL logs were not run.

Figure 7-17: DST-2,-3,-4,-5 Alasehir-1

$7.2.5.$ Volumetrics

$7.2.5.1.$ Approach

We used a probabilistic method using the industry-standard REP software to combine ranges of input parameters to derive distributions of contingent and prospective resources.

$7.2.5.2.$ Gross Rock Volume

Area and net pay

RISC has adopted a net pay and area approach to calculate the gross rock volume for the Alasehir Oil Field. This approach was based on the relatively thin nature of the oil sands, the occurrence of oil multiple sands and the stratigraphic nature of the trap. The areas have been calculated from the Intra Alasehir B Depth Structure Map with the P90 area (4.1 km²) of the field is a closing contour of 1,960 mss which is 10m down dip from the Alasehir-1 oil well. A net pay range of 9.9m (P90), to 19.6m (P10) was used to calculate the GRV.

$7.2.5.3.$ Reservoir and Fluid Parameters

The reservoir and fluid parameters for the Alasehir Field were based upon the Petrophysical data from Sarakiz-2.

$7.2.5.4$ Recovery Factor

The recovery factor for the Alasehir Oil field was assumed to range from 10 to 30% based on the TAF analogue.

Summary of Volumetric Input Parameters $7.2.5.1$

The following Table 7-5 is a summary of the area and net pay thickness values plus the reservoir input parameters form the RISC petrophysical interpretation for the Sarikiz Oil Field which have been applied to the Alasehir Oil Field.

Name	Unit	Shape	Min	P ₉₀	P50	P ₁₀	Max	Mode	Mean	Edit
Area	km2	Beta	2.45	4.14	6.17	8.41	10.9	6.00	6.23
Thickness	$\mathbf{m}$	Beta	5.00	9.99	14.8	19.6	24.0	15.0	14.8	444
Shape factor	%	Single	100	100	100	100	100	100	100	$\cdots$
Dea, of fill	%	Single	100	100	100	100	100	100	100
Net-to-gross	%	Single	100	100	100	100	100	100	100	$\cdots$
Porosity	%	Beta	12.1	14.0	16.0	18.0	19.9	16.0	16.0	144
Sw	%	Beta	40.0	50.7	58.7	65.4	70.0	60.0	58.3	44
FVF (Bo)	rb/stb	Beta	0.865	1.00	1.15	1.30	1.45	1.15	1.15	ùй.
Oil rec fac	%	Beta	3.00	9.88	19.9	32.0	47.9	18.0	20.5	$\cdots$

Table 7-5: Volumetric Inputs for Alasehir Oil Field

Contingent Resources $7.2.5.2.$

The estimate of the contingent resources for the Alasehir Oil Field is given in Table 7-6.

Contingent Oil Resources (MMstb)
	Equity	1 ^C	2C	3 ^C
Alasehir Oil Field	100%	2.53	6.01	12.5
Petroz Ltd	75%	1.90	4.51	9.38
Petrako	25%	0.63	1.50	3.13

Table 7-6: Contingent Resources for the Alasehir Oil Field (100%) as at 30 September 2015

$7.2.6.$ Well Spacing and Recovery

We have adopted an 80 acre spacing with the following initial productivity and recovery parameters for the Alasehir area. Production forecasts were generated by applying a conventional decline to an estimated range of suitable initial oil rates, and recoveries. A thorough review of recoveries from the TAF analogues (in the public domain) suggested per well oil recovery of approximately 200 to almost 500 Mstb/well, for well spacing of 80 Acres. Assuming exponential decline, the forecasts per well are shown in Figure 7-18. A tabulation of well numbers and recovery is also given in Table 8-1. Initial oil rate was prorated for both net pay and water-oil cut to the test results from Sarikiz -2.

Alasehir	80 acre spacing
Conf. Level	Area	STOIIP	EUR	RF	Wells	EUR/well	Thickness	IP
	km ₂	MMstb	MMstb	%	#	Mstb	m	stb/d
P90	4.1	17.9	2.5	14%	13.0	192	13	210
P50	6.4	31.7	6.0	19%	20.0	300	15	325
P ₁₀	8.2	52.7	12.5	24%	26.0	481	19	525

Figure 7-18 Alasehir Single Well Production Forecasts

Development Plans and Forecasts 8.

We have produced field development plans with production profiles and cost estimates based on the Petroz approach detailed above for the P90, P50 and P10 resource cases for both Alasehir and Sarikiz. We have assumed that a total of 6 wells can be drilled per year using a single drilling rig and we have phased our development wells accordingly. A summary of the field development plan is shown in Table 8-1 below.

		Sarikiz		Alasehir
	1C Case	2C Case	3C Case	1C Case	2C Case	3C Case
# of Wells	13	15	18	13	20	26
oil Peak rate (bbl/d)	1,200	2,200	3,800	2,050	3,900	7,000
Contingent Resource (MMstb)	1.4	3.1	5.8	2.5	6.0	12.5
First oil (yr)	2016	2016	2016	2018	2018	2018

Table 8-1 Field Development Plan Summary

The field development plans are based on vertical development wells drilled from 6 well pad clusters. Production fluids will be artificially lifted using beam pumps and wellsite facilities will include; production and test manifolds with Coriolis flow meters. Produced fluids will be gathered using steel flowlines to a central oil processing facility. At the processing facility oil, water and gas will be separated and treated separately. Produced oil will be treated to reduce the BS&W content to a specification that will be acceptable to the nearby Izmir oil refinery. The Reid vapour pressure (RVP) will also be reduced so the oil is suitable for loading into trucks to be transported to the oil refinery. Produced water will be treated to remove oil and will be stored in evaporation ponds for disposal. Produced gas will be used to generate power for the production facilities and well sites, excess gas will be flared.

Previous fluids produced from the Sarikiz field had high levels of CO2 with saline formation water. Both of these fluids are highly corrosive and we have assumed that all materials used in the development of these fields will have corrosion resistant coatings or be composed or corrosion resistant alloys.

The Sarikiz development is assumed to proceed first with the Alasehir development following and comprising a new development separate to the Sarikiz facilities.

Production Forecasts 8.1.

A summary of the production forecast for each development case is shown in the charts below. The bars show annual production rate in bbl/d while the lines show cumulative production in MMbbl.

Figure 8-1 Sarikiz Production Forecast Summary

Figure 8-2 Alasehir Production Forecast Summary

$8.2.$ Cost Estimates

Petroz has presented capital and operating cost estimates for wells and facilities for their development plans and provided associated cost forecasts in an economic model. We have reviewed these cost estimates and produced our own cost forecasts based on our own estimates of well and facility costs and the development plans outlined above. The major differences between the Petroz costs and RISC's estimates is higher well costs carried by RISC and operational costs being separated into a fixed and variable component by RISC.

$8.2.1.$ Well Costs

Petroz have estimated the initial Sarikiz well cost to be US\$2.2 million per well based on a 1750m TD, a 21 day drill and complete duration and a rig rate of US\$15k/d. The implied average penetration rate based on these assumptions is approximately 80m/d.

We have reviewed the time vs depth curves for the previous wells drilled in the field to understand the likely duration of future development wells. Note that we have excluded time for DST's or other testing from our calculations. A summary of the well durations is shown in Table 8-2 below.

Well	Year	Depth	Duration	m/d
Alasehir 1	1998	2375	49	48.5
Sarikiz 1	2000	1963	36	54.5
Sarikiz 1A	2000	1596	27	59.1
E Sarikiz 1	2001	2298	38	60.5
Sarikiz 2	2008	1847	44	42.0
Sarikiz 3	2009	1900	46	41.3

It can be seen that well performance varies from 40 m/day to 60 m/day in the previous wells. While we accept that with better drilling practices and equipment higher penetration rates may be achievable, we have not sighted any studies which support this.

We have therefore assumed that the first appraisal well in each of the Alasehir and the Sarikiz fields will have a penetration rate of 55 m/day. Future wells may well have improved performance due to learning from experience, and we have therefore used the 80m/d penetration rate to show sensitivity to improved performance..

We have used the anticipated well durations together with an estimate of drill rig day rate (US\$15,000/day as advised by Petroz) and drilling support service day rate (US\$10,000/day) in our internal well cost estimation tool to produce estimated well costs based on the range of anticipated performance. These are outlined in Table 8-3. Average reservoir depths for Alasehir are expected to be approximately 400m deeper than for Sarikiz, resulting in increased time and cost.

Field	Average penetration rate 55-60m/d	Average penetration rate 80 _m /d
Sarakiz (1750m TD)	2.6	2.3
Alasehir (2150m TD)	3.1	2.7

Table 8-3 Estimated unit well drilling and completion costs US\$ million

The scope of the above wells includes:

Mob/demob
Drilling to TD
A basic log evaluation suite
Running casing, tubing, perforations and suspending the well

In addition we understand that well completion and testing will be carried out using a separate workover rig, which will be brought to site once the drill rig has demobilized.

Using a day rate of approximately \$7000/day for the workover rig we estimate testing costs will be US\$150-250k depending upon the length of test (assumed to be 10-15 days). These costs are in addition to the estimated well costs above.

Gathering costs per well are estimated to be US\$280,000 including wellsite facilities and power and communications distribution systems linking the well sites with the central processing facility.

We consider that with a continuous operation, implementation of continuous improvement systems from a cost focused operator could reduce the unit well costs by 30%.

$8.2.2.$ Facilities Costs

Petroz have estimated a total of US\$4.5 million for each of the Sarikiz and Alasehir fields mid cases to cover 3D seismic, Facilities and Engineering costs. We have used an internal cost estimation tool to estimate the cost of installing oil processing facilities in a central location near the Sarikiz field. We have estimated the cost for four different facility types to match the production rates expected from the different development cases.

The basic facility type addressed is a central production facility (CPF) comprising of the following unit operations;

× Fluid receiving system including manifold, slugcatcher and metering system,
× Three phase separation system,
٠ Oil dewatering and desalting system,
n Water treatment system,
× HP and LP gas system including turbine and flare
$\blacksquare$ Dual fuel power generation and distribution system,
$\blacksquare$ Water, nitrogen and compressed air utility systems
Water evaporation ponds 價
п Oil storage and truck loading system
Instrumented control system п

The facility will also have a central control room, maintenance workshop and storeroom facilities.

Four sizes of CPF facility have been designed; a 1,000 bbl/d plant matching the peak production rate of the Sarikiz P90 case, a 2,000 bbl/d plant matching the peak production rate of the Sarikiz P50 case and the Alasehir P90 case, a 4,000 bbl/d plant matching the peak production rate of the Sarikiz P10 case and the Alasehir P50 case and a 7,000 bbl/d plant matching the peak production rate of the Alasehir P10 case. Note that during the single well appraisal phase of the fields the production rate is too small to justify a permanent CPF and we have assumed that small leased facilities (250bbl/d) will be utilised in the individual fields with the costs being outlined in the Operational cost section below.

The costs of the different processing facilities are outlined in the table below.

Table 8-4 Oil Processing Facilities Cost Summary

Facility	Cost (US\$ MM)	Processing Capacity (bbl/d)
Sarikiz 1C Case	6	1,000
Sarikiz 2C/Alasehir 1C Case	9	2,000
Alasehir 2C/Sarikiz 3C Case	17	4,000
Alasehir 3C Case	23	7,000

$8.2.3.$ Operational Costs

Petroz have presented operational costs for their development of US\$3.75/bbl for trucking costs and US\$6.25/bbl for production costs. Petroz have also estimated a US\$500,000 workover cost per operation and have assumed 1-2 workovers per well for the life of the fields.

We have generated a fixed operational cost for each of the development cases based on the scope of the facilities required. We have also generated a variable operating cost to cover trucking and production costs and workover costs.

The fixed operating cost assumptions are:

US\$1 million p.a. for CPF operations
US\$1 million p.a. for G&A costs
5% of CPF facility capex p.a. for maintenance of facilities
US\$500,000 p.a. for rental of a 250 bbl/d processing module to be used in the appraisal phases of the fields life

The variable operating cost assumptions are:

US\$3.75/bbl for trucking of oil to the Izmir refinery i.
US\$6.25/bbl for production costs when using leased production facilities and US\$1.875/bbl for × production costs when using a purpose built CPF
US\$350,000 per workover with one workover assumed per well every three years п

8.2.4. Abandonment Costs

Petroz have advised that the operator estimates an abandonment cost of \$80-100k per well, however there is no supporting information available for this estimate. We estimate the following costs for abandonment at the end of field life using a drilling rig;

\$300,000 per well for Plug and Abandonment
20% of facilities capex to decommission and remove permanent facilities $\blacksquare$

However if a low cost options such as a workover hoist can be utilized for well abandonment, costs in the order of those quoted from the operator could be achieved.

$8.3.$ Cost Forecasts

The charts below show capital and operating cost forecasts for each of the development cases. The bars show annual Capital and Operating costs in US\$ millions and the lines show the annual production rate in bbl/d.

Figure 8-3: Sarikiz 1C, 2C and 3C Cost Forecasts

Figure 8-4 Alasehir 1C, 2C and 3C Cost Forecasts

ARISC

Prospective Resources 9.

$9.1.$ Sarikiz Deep Lead

$9.1.1.$ Seismic Interpretation

The Sarikiz Deep Lead is located beneath the existing Sarikiz Oil Field at the deeper Intra Alasehir B level (Figure 9-1). The 2D seismic lines provide adequate coverage to define the major faults, however, a comprehensive 3D seismic survey is required to define the complex faulting across the lead. The Intra Alasehir (Purple) horizon is the key event for the evaluation of the lead.

Figure 9-1: Intra Alasehir B Depth Structure Map - Sarikiz Deep Lead

The well calibration for the seismic interpretation is poor with only the Alasehir-1 well checkshot survey as the time / depth data for the licence area.

The Time structure maps have been depth converted using the Alasehir-1 time/depth function from the well checkshot Figure 7-13. The depth conversion function has the formulae: survey Depth+366.13t2 +779.22t+11.36

The lead is a structural / stratigraphic trap with 3 way closure and updip seal against a basement fault within Early to Middle Miocene clastic reservoirs of the Alasehir Fm Figure 9-1 and Figure 9-2 (Line location in Figure 9-1). The (P10) area of the field is 5.2 $km^2$ with the lowest closing contour for the structure and a value of 1,850 mss. None of the existing Sarikiz wells have drilled this section however, the Alasehir Oil Field is at this stratigraphic level and is the analogue for this lead. The relief on the lead is 500m.

Figure 9-2: Line IZD-98-204 - Sarikiz Deep Lead

$9.1.2.$ Volumetrics

$9.1.2.1.$ Approach

We used a probabilistic method using the industry-standard REP software to combine ranges of input parameters to derive distributions of prospective resources.

$9.1.2.2.$ Gross Rock Volume

Area and net pay

RISC has adopted a net pay and area approach to calculate the gross rock volume for the Sarikiz Deep Lead. This approach was based on the relatively thin nature of the oil sands, the occurrence of oil multiple sands and the stratigraphic nature of the trap. The areas have been calculated from the Intra Alasehir B Depth Structure Map with the P10 area (5.2 km²) of the field is a closing contour of 1,850 mss. A net pay range of 9.9m (P90), to 19.6m (P10) was used to calculate the GRV.

$9.1.2.3.$ Reservoir and Fluid Parameters

The reservoir and fluid parameters for the Sarikiz Deep Lead were based upon the Petrophysical data from Sarakiz-2.

$9.1.2.4.$ Recovery Factor

The recovery factor for the Sarikiz Deep Lead was assumed to range from 5 to 30% based on the observed porosity ranges, and potential permeability range.

$9.1.2.5.$ Summary of Volumetric Input Parameters

The following Table 9-1 is a summary of the area and net pay thickness values plus the reservoir input parameters from the RISC petrophysical interpretation for the Sarikiz Oil Field which have been applied to the Sarikiz Deep Lead.

	Name	Unit	Shape	Min	P90	P50	P10	Max	Mode	Mean	Edit
ь	Area	km2	Lognor	1.05	2.00	3.22	5.20	9.87	2.81	3.46	$\cdots$
	Thickness	m	Beta	5.00	9.99	14.8	19.6	24.0	15.0	14.8	$\cdots$
	Shape factor	%	Single	100	100	100	100	100	100	100
	Dea, of fill	%	Single	100	100	100	100	100	100	100
	Net-to-gross	%	Single	100	100	100	100	100	100	100	8.9.8
	Porosity	%	Beta	12.1	14.0	16.0	18.0	19.9	16.0	16.0	1.111
	Sw	%	Beta	40.0	50.7	58.7	65.4	70.0	60.0	58.3	1000
	FVF (Bo)	rb/stb	Beta	0.865	1.00	1.15	1.30	1.45	1.15	1.15	144.1
	Oil rec fac	%	Beta	3.00	9.88	19.9	32.0	47.9	18.0	20.5

Table 9-1: Volumetric Inputs for the Sarikiz Deep Lead

$9.1.2.6.$ Prospective Resources

The estimate of the prospective resources for the Sarikiz Deep Lead is given in Table 9-2.

Unrisked Prospective Oil Resources (MMstb)
Lead	Equity	Low Estimate	Best Estimate	High Estimate	Chance of Success
Sarikiz Deep Lead	100%	1.29	3.21	7.23	21%
Petroz Ltd	75%	1.06	2.33	4.37
Detrako	つち%	በ 35	በ 78	1A5

Table 9-2: Prospective Resources for the Sarikiz Deep Lead

$9.2.$ West Alasehir Lead

$9.2.1.$ Seismic Interpretation

The West Alasehir Lead is located 2.5 km west of the Alasehir-1 oil discovery (Figure 9-3). The 2D seismic lines provide only moderate coverage (2.5 km dip line spacing) to define the major faults and therefore a comprehensive 3D seismic survey is required to define the complex faulting across the lead. The Intra Alasehir (Purple) horizon is the key event for the evaluation of the lead.

Figure 9-3: Intra Alasehir B Depth Structure Map - West Alasehir Lead

The well calibration for the seismic interpretation is poor with only the Alasehir-1 well checkshot survey as the time / depth data for the licence area.

The Time structure maps have been depth converted using the Alasehir-1 time/depth function from the well function has the formulae: 7-13. The depth conversion checkshot survey Figure Depth+366.13t2+779.22t+11.36

The lead is a structural / stratigraphic trap with 3 way closure and updip seal against a basement fault within Early to Middle Miocene clastic reservoirs of the Alasehir Fm Figure 9-3 and Figure 9-4 (Line location in Figure 9-3). The (P10) area of the field is 11.2 km² with the lowest closing contour for the structure and a value of 2,220 mss. The Alasehir Oil Field is at this stratigraphic level and is the analogue for this lead. The relief on the lead is 840m.

Figure 9-4: Strike Line through Alasehir 1 well - West Alasehir Lead

$9.2.2.$ Volumetrics

$9.2.2.1.$ Approach

We used a probabilistic method using the industry-standard REP software to combine ranges of input parameters to derive distributions of prospective resources.

$9.2.2.2.$ Gross Rock Volume

Area and net pay

RISC has adopted a net pay and area approach to calculate the gross rock volume for the Sarikiz Deep Lead. This approach was based on the relatively thin nature of the oil sands, the occurrence of oil multiple sands and the stratigraphic nature of the trap. The areas have been calculated from the Intra Alasehir B Depth Structure Map with the P10 area (11.2 km²) of the field is a closing contour of 2,220 mss. A net pay range of 9.9m (P90), to 19.6m (P10) was used to calculate the GRV.

$9.2.2.3.$ Reservoir and Fluid Parameters

The reservoir and fluid parameters for the Sarikiz Deep Lead were based upon the Petrophysical data from Sarakiz-2.

$9.2.2.4$ Recovery Factor

The recovery factor for the Sarikiz Deep Lead was assumed to range from 5 to 30% based on the observed porosity ranges, and potential permeability range.

Summary of Volumetric Input Parameters $9.2.2.5.$

The following Table 9-3 is a summary of the area and net pay thickness values plus the reservoir input parameters from the RISC petrophysical interpretation for the Sarikiz Oil Field which have been applied to the West Alasehir Lead.

Name	Unit	Shape	Min	P90	P50	P10	Max	Mode	Mean	Edit
Area	km2	Lognor	1.24	3.00	5.80	11.2	27.1	4.45	6.61	1.11
Thickness	m	Beta	5.00	9.99	14.8	19.6	24.0	15.0	14.8	$-0.05$
Shape factor	%	Single	100	100	100	100	100	100	100	18.5
Deg. of fill	%	Single	100	100	100	100	100	100	100	$***$
Net-to-gross	%	Single	100	100	100	100	100	100	100	1000
Porosity	%	Beta	12.1	14.0	16.0	18.0	19.9	16.0	16.0	3.13
Sw	%	Beta	40.0	50.7	58.7	65.4	70.0	60.0	58.3	1.11
FVF (Bo)	rb/stb	Beta	0.865	1.00	1.15	1.30	1.45	1.15	1.15	$+1.4$
Oil rec fac	%	Beta	3.00	9.88	19.9	32.0	47.9	18.0	20.5	$\cdots$

Table 9-3: Volumetric Inputs for the West Alasehir Lead

Prospective Resources $9.2.2.6.$

The estimate of the prospective resources for the West Alasehir Lead is given in Table 9-4.

Table 9-4: Prospective Resources for the West Alasehir Lead

Unrisked Prospective Oil Resources (MMstb)
Lead	Equity	Low Estimate	Best Estimate	High Estimate	Chance of Success
West Alasehir Lead	100%	2.08	5.74	14.70	21%
Petroz Ltd	75%	1.56	4.30	11.02
Petrako	25%	0.52	1.44	3.68

Chance of Success $9.3.$

Risking methodology $9.3.1.$

Prospectivity in the Alasehir Basin, onshore Turkey is fairly well explored, and it clearly offers exploration potential. As presented in our report, one potential play is defined and has been proven by the oil discovery in Alasehir-1 so by definition the play risk is 1. On the other hand, prospect risks are specific to the various features, and assume that the play is proven.

Sarikiz Deep Lead Prospect Risk $9.3.2.$

Charge - high confidence, very likely to occur as this lead has access to the same source kitchen as the Alasehir Oil Field but on the opposite of the trough. Faulting through this section is expected to provide migration route. Very short migration pathway distance reduces risk. POS: 0.85

Reservoir - high confidence, very likely to occur; as nearby wells with Miocene sands. Stratigraphic model implies sands are regionally present. Probability 0.85.

Trap – moderate confidence, very likely to occur, given play as defined; trap geometry defined by detail 2D seismic coverage but faulting complexity requires 3D coverage. Trap style is the same as the Alasehir Oil Filed, 2.5 km to the north. Probability 0.6.

Seal - moderate to fair confidence, may or may not occur and this is the key risk for the lead as lateral seal of the oil sands against the basin margin fault can be risky. Probability 0.5.

The various chances of success, including total probabilities, are summarised in Table 9-5.

Exploration Risk Assessment: Sarikiz Deep Lead
Play Chance	Source	Reservoir	Seal		Overall Play POS
	1
Lead Chance	Migration	Reservoir	Seal	Trap
	0.85	0.85	0.5	0.6	0.21

Table 9-5: Probability of Success - Sarikiz Deep Lead

$9.3.3.$ West Alasehir Lead Prospect Risk

Charge $-$ high confidence, very likely to occur as this lead has access to the same source kitchen as the Alasehir Oil Field but on the opposite of the trough. Faulting through this section is expected to provide migration route. Very short migration pathway distance reduces risk. POS: 0.85

Reservoir - high confidence, very likely to occur; as nearby wells with Miocene sands. Stratigraphic model implies sands are regionally present. Probability 0.85.

Seal - moderate to fair confidence, may or may not occur and this is the key risk for the lead as lateral seal of the oil sands against the basin margin fault can be risky. Probability 0.5.

The various chances of success, including total probabilities, are summarised in Table 9-6.

Exploration Risk Assessment: West Alasehir Lead
Play Chance	Source	Reservoir	Seal		Overall Play POS
	1	1
Lead Chance	Migration	Reservoir	Seal	Trap
	0.85	0.85	0.5	0.6	0.21

Table 9-6: Probability of Success - West Alasehir Lead

10. Economics

RISC carried out a discounted cashflow analysis of the Sarikiz and Alasehir oil fields to determine unrisked net present values (NPV, 10% discount factor) which incorporate economic cut-offs to field production.

10.1. Fiscal Terms

The Turkish Petroleum Fiscal Regime relevant to the Sarikiz and Alasehir oil fields is a tax/royalty regime consisting of a simple royalty and corporate tax. No special taxes or charges apply.

payable at a rate of 12.5% of petroleum production. Royalty

payable at a rate of 20% at a company level ring fenced around oil & gas activities. Corporate tax Allowable deductions include operating costs, royalty, exploration costs (expensed), development capital (depreciated using the straight line or declining balance method over 5 years) and unused deductions carried forward for maximum of 5 vears.

10.2. Economic parameters

Valuation date 30 September 2015

Oil Price

Oil production is assumed to be sold at prices reflected by the current Brent forward curve out to 2019 and maintained flat in real terms from 2019 (approximately US\$60/bbl). No adjustment for oil quality is applied.

Table 10-1 Brent Oil Forward Curve

2015	2016	2017	2018	2019
43.24	47.74	54.73	58.35	60.07

Escalation

Prices and costs are escalated at 2.5% per annum from 2016

10.3. Unrisked Valuation

RISC has carried out a discounted cash flow analysis of the contingent resources within the Sarikiz and Alasehir oil fields to demonstrate the economic potential of future development. The net present values have been estimated using a 10% nominal discount factor (NPV10) and incorporate economic cut-offs to field production. The net present values shown in Table 10-2 have not been adjusted for technical and commercial risk and market factors and should not be construed as a fair market value.

Net to Petroz (75%)	Economic cut-off	Economic Recovery MMstb	Unrisked NPV10 (US\$ million)	Unit NPV (NPV10 US\$/bbl)
Sarikiz - 3C case	$Jan-27$	4.3	56	13
Sarikiz - 2C case	$Jan-26$	2.2	18	8
Sarikiz $-1C$ case	Jan-24	1.0	$-6$	-6
Alasehir - 3C case	$Jan-31$	9.3	128	14
Alasehir $-2C$ case	$Jan-29$	4.4	45	10
Alasehir - 1C case	$Jan-27$	1.8	8	4

Table 10-2 Sarikiz and Alasehir Unrisked NPV (Petroz net 75%)

Note that if a 30% cost reduction in well costs could be achieved (discussed in section 8.2.1) an approximate uplift to the NPV's of 23% for the Sarikiz 2C case and 12% for the Alasehir 2C case would result.

11. Declarations

11.1. Qualifications

RISC is an independent oil and gas advisory firm. The RISC staff engaged in this assignment include professionally qualified engineers, geoscientists and analysts, each with many years of relevant experience and most have in excess of 20 years.

The preparation of this report has been supervised by Mr. Geoffrey Barker, RISC Partner. He has over thirty years of global experience in the upstream hydrocarbon industry, with extensive expertise in the areas of asset valuation, business strategies, evaluation of conventional and non-conventional petroleum (coal seam gas and tight gas), due diligence assessment for mergers, acquisitions and project finance requirements and reserves assessment/certification and preparation of Independent Technical Specialist reports. Mr. Barker is a Past Chairman of the SPE WA Section, a past member of the SPE International's Oil and Gas Reserves Committee 2007-2009, and is a co-author of the Guidelines for Application of the Petroleum Resources Management System published by the SPE in November 2011 (Chapter 8.5 Coal Bed Methane). Mr Barker is a Member of the Society of Petroleum Engineers (SPE), and holds a BSc (Chemistry), Melbourne University, 1980 and a M.Eng.Sc (Pet Eng), Sydney University, 1989 and is a qualified petroleum reserves and resources evaluator (QPPRE) as defined by ASX listing rules.

RISC was founded in 1994 to provide independent advice to companies associated with the oil and gas industry. Today the company has approximately 40 highly experienced professional staff at offices in Perth and Brisbane, Australia and London, UK. We have completed over 1500 assignments in 68 countries for nearly 500 clients. Our services cover the entire range of the oil and gas business lifecycle and include:

Oil and gas asset valuations, expert advice to banks for debt or equity finance; п
$\blacksquare$ Exploration/Portfolio management;
Field development studies and operations planning; п
Reserves assessment and certification, peer reviews; $\blacksquare$
$\blacksquare$ Gas market advice;
Independent Expert/Expert Witness;
Strategy and corporate planning. ×

11.2. VALMIN Code

This Report has been prepared by RISC. This Report has been prepared in accordance with the Code for the Technical Assessment and Valuation of Mineral and Petroleum Assets and Securities for Independent Expert Reports 2005 Edition ("The VALMIN Code") as well as the Australian Securities and Investment Commission (ASIC) Regulatory Guides 111 and 112.

11.3. Petroleum Resources Management System

In the preparation of this Report, RISC has complied with the guidelines and definitions of the Petroleum Resources Management System approved by the Board of the Society of Petroleum Engineers in 2007 (PRMS).

11.4. Independence

RISC is not operating under an Australian financial services licence in providing this report.

In accordance with regulation 7.6.01(1)(u) of the Corporations Regulation 2001. RISC makes the following disclosures:

RISC is independent with respect to Dempsey and Petroz and confirms that there is no conflict of $\blacksquare$ interest with any party involved in the assignment;
× Under the terms of engagement between RISC and Dempsey for the provision of this report, RISC will receive a time-based fee, with no part of the fee contingent on the conclusions reached, or the content or future use of this report. Except for these fees, RISC has not received and will not receive any pecuniary or other benefit whether direct or indirect for or in connection with the preparation of this report;
Neither RISC nor any of its personnel involved in the preparation of this report have any material $\blacksquare$ interest in Dempsey, Petroz or in any of the properties described herein;
RISC has not undertaken any assignments for Dempsey or Petroz for the past two years.

11.5. Limitations

The assessment of petroleum assets is subject to uncertainty because it involves judgments on many variables that cannot be precisely assessed, including reserves, future oil and gas production rates, the costs associated with producing these volumes, access to product markets, product prices and the potential impact of fiscal/regulatory changes.

The statements and opinions attributable to RISC are given in good faith and in the belief that such statements are neither false nor misleading.

In carrying out its tasks, RISC has considered and relied upon information obtained from Petroz as well as information in the public domain. The information provided to RISC has included both hard copy and electronic information supplemented with discussions between RISC and key Petroz staff.

Whilst every effort has been made to verify data and resolve apparent inconsistencies, we believe our review and conclusions are sound, but neither RISC nor its servants accept any liability, except any liability which cannot be excluded by law, for its accuracy, nor do we warrant that our enquiries have revealed all of the matters, which an extensive examination may disclose.

In particular, we have not independently verified property title, encumbrances or regulations that apply to this asset(s). We have not independently confirmed the status of the permit titles.

RISC has also not audited the opening balances at the economic evaluation date of past recovered and unrecovered development and exploration costs, undepreciated past development costs and tax losses.

We believe our review and conclusions are sound but no warranty of accuracy or reliability is given to our conclusions.

Our review was carried out only for the purpose referred to above and may not have relevance in other contexts.

11.6. Consent

RISC has consented to this report, in the form and context in which it appears, being included in the announcement to the ASX in December 2015 by Dempsey Minerals Ltd. Neither the whole nor any part of this report nor any reference to it may be included in or attached to any other document, circular, resolution, letter or statement without the prior consent of RISC.

This Report is authorised for release by Mr. Geoffrey Barker, RISC Partner dated 21 December 2015.

Geoffrey J Barker

Partner

Bibliography

Oner, Z. D. (2014). Fault kinematics in supradetachment basin formation, Menderes core complex of western Turkey . Tectonophysics.
Turk, S. (2014). Seismic Structure and Tectonics of the Alasehir-Gediz Graben Western Turkey. Thesis, Miami University, Oxford Ohio, Department of Geology & Environmental Earth Science.

Appendix 1: List of terms

The following table lists abbreviated terms, along with a brief definition, that are commonly used in the oil and gas industry and which may be used in this report.

Abbreviation	Definition
1P	Equivalent to Proved reserves or Proved in-place quantities, depending on the context.
1Q	1st Quarter
2P	The sum of Proved and Probable reserves or in-place quantities, depending on the context.
2Q	2nd Quarter
2D	Two Dimensional
3D	Three Dimensional
4D	Four Dimensional - time lapsed 3D in relation to seismic
3P	The sum of Proved, Probable and Possible Reserves or in-place quantities, depending on the context.
3Q	3rd Quarter
4Q	4th Quarter
AFE	Authority for Expenditure
Bbl	US Barrel
BBL/D	US Barrels per day
BCF	Billion (109) cubic feet
BCM	Billion (109) cubic meters
BFPD	Barrels of fluid per day
BOPD	Barrels of oil per day
BTU	British Thermal Units
BOE	barrels of oil equivalent (equivalent to 1 bbl oil, 1 bbl condensate, 1 bbl NGL, 6,000 scf gas)
BOEPD	US barrels of oil equivalent per day
BWPD	Barrels of water per day
°C	Degrees celsius
Capex	Capital expenditure
CAPM	Capital asset pricing model
CGR	Condensate Gas Ratio - usually expressed as bbl/MMscf
Contingent Resources	Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources are a class of discovered recoverable resources as defined in the SPE-PRMS.
CO ₂	Carbon dioxide
СP	Centipoise (measure of viscosity)
CPI	Consumer Price Index
DEG	Degrees

Abbreviation	Definition 20 S.S. PIA YAK (YSRAES R
DHI	Direct hydrocarbon indicator
Discount Rate	The interest rate used to discount future cash flows into a dollars of a reference date
DST	Drill stem test
E&P	Exploration and Production
EG	Gas expansion factor. Gas volume at standard (surface) conditions / gas volume at reservoir conditions (pressure & temperature)
EIA	US Energy Information Administration
EMV	Expected Monetary Value
EOR	Enhanced Oil Recovery
ESP	Electric submersible pump
EUR	Estimated ultimate recovery
Expectation	The mean of a probability distribution
F	Degrees Fahrenheit
FDP	Field Development Plan
FEED	Front End Engineering and design
FID	Final investment decision
FM	Formation
FPSO	Floating Production Storage and offtake unit
FWL	Free Water Level
FVF	Formation volume factor
GIIP	Gas Initially In Place
GJ	Giga (10 ⁹ ) joules
GOC	Gas-oil contact
GOR	Gas oil ratio
GRV	Gross rock volume
GSA	Gas sales agreement
GTL	Gas To Liquid(s)
GWC	Gas water contact
H2S	Hydrogen sulphide
HHV	Higher heating value Internal diameter
ID	Internal Rate of Return is the discount rate that results in the NPV being equal to zero.
IRR JV(P)	Joint Venture (Partners)
Kh	Horizontal permeability
km ₂	Square kilometres
Krw	Relative permeability to water
Κv	Vertical permeability

Abbreviation	Definition
kPa	Kilo (thousand) Pascals (measurement of pressure)
Mstb/d	Thousand Stock tank barrels per day
LIBOR	London inter-bank offered rate
LNG	Liquefied Natural Gas
LTBR	Long-Term Bond Rate
m	Metres
MDT	Modular dynamic (formation) tester
mD	Millidarcies (permeability)
MJ	Mega (10 ⁶ ) Joules
MMbbl	Million US barrels
MMscf(d)	Million standard cubic feet (per day)
MMstb	Million US stock tank barrels
MOD	Money of the Day (nominal dollars) as opposed to money in real terms
MOU	Memorandum of Understanding
Mscf	Thousand standard cubic feet
Mstb	Thousand US stock tank barrels
Mtpa	Millions of tons per annum
MPa	Mega (10 ⁶ ) pascal (measurement of pressure)
mss	Metres subsea
MSV	Mean Success Volume
mTVDss	Metres true vertical depth subsea
MW	Megawatt
NPV	Net Present Value (of a series of cash flows)
NTG	Net to Gross (ratio)
ODT	Oil down to
GIIP	Original Gas In Place
STOIIP	Original Oil in Place
Opex	Operating expenditure
OWC	Oil-water contact
P90, P50, P10	90%, 50% & 10% probabilities respectively that the stated quantities will be equalled or exceeded. The P90, P50 and P10 quantities correspond to the Proved (1P), Proved + Probable (2P) and Proved + Probable + Possible (3P) confidence levels respectively.
PBU	Pressure build-up
PJ	Peta (10 ¹⁵ ) Joules
POS	Probability of Success

Abbreviation	Definition
Possible Reserves	As defined in the SPE-PRMS, an incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.
Probable Reserves	As defined in the SPE-PRMS, an incremental category of estimated recoverable volumes associated with a defined degree of uncertainty. Probable Reserves are those additional Reserves that are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.
Prospective Resources	Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations as defined in the SPE-PRMS.
Proved Reserves	As defined in the SPE-PRMS, an incremental category of estimated recoverable volumes associated with a defined degree of uncertainty Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. Often referred to as 1P, also as "Proven".
PSC.	Production Sharing Contract
PSDM	Pre-stack depth migration
PSTM	Pre-stack time migration
psia	Pounds per square inch pressure absolute
p.u.	Porosity unit e.g. porosity of 20% +/- 2 p.u. equals a porosity range of 18% to 22%
PVT	Pressure, volume & temperature
QA/QC	Quality Assurance/ Control
rb/stb	Reservoir barrels per stock tank barrel under standard conditions
RFT	Repeat Formation Test
Real Terms (RT)	Real Terms (in the reference date dollars) as opposed to Nominal Terms of Money of the Day
Reserves	RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorised in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.
RT	Measured from Rotary Table or Real Terms, depending on context
SC	Service Contract
scf	Standard cubic feet (measured at 60 degrees F and 14.7 psia)
Sg	Gas saturation
Sgr	Residual gas saturation

Abbreviation	Definition
SRD	Seismic reference datum lake level
SPE	Society of Petroleum Engineers
SPE-PRMS	Petroleum Resources Management System, approved by the Board of the SPE March 2007 and endorsed by the Boards of Society of Petroleum Engineers, American Association of Petroleum Geologists, World Petroleum Council and Society of Petroleum Evaluation Engineers.
s.u.	Fluid saturation unit. e.g. saturation of 80% +/- 10 s.u. equals a saturation range of 70% to 90%
stb	Stock tank barrels
STOIIP	Stock Tank Oil Initially In Place
Sw	Water saturation
TCM	Technical committee meeting
Tcf	Trillion (10 ¹² ) cubic feet
ΤJ	Tera (10 ¹² ) Joules
TLP	Tension Leg Platform
TRSSV	Tubing retrievable subsurface safety valve
TVD	True vertical depth
US\$	United States dollar
US\$ million	Million United States dollars
WACC	Weighted average cost of capital
WHFP	Well Head Flowing Pressure
Working interest	A company's equity interest in a project before reduction for royalties or production share owed to others under the applicable fiscal terms.
WPC	World Petroleum Council
WTI	West Texas Intermediate Crude Oil

AI assistant

GALAN LITHIUM LIMITED — Capital/Financing Update 2015

64995_rns_2015-12-21_fcce1904-5917-40ab-b838-235a005fc242.pdf

ASX ANNOUNCEMENT

DEMPSEY UPDATE ON PETROZ LIMITED ACQUISITION

Loan Obligations under Agreement

Capital Raising

Acquisition Completion

Independent Expert's Report

Economic Assessment and Sarikiz-SPP 1 well

For further information contact: Nathan McMahon

Competent Person

December 2015

Table of contents

List of figures

List of tables

Independent Expert Report on Petroz Limited's interests in Licence L21A Alasehir & Sarikiz Oil Fields, Onshore Turkey

Introduction $\mathbf{1}$ .

$2.$ Summary

$2.1.$ Overview

$2.2.$ Resource Summary

Table 2-1: L21A Contingent Resources - as at 30 September 2015

Table 2-2: L21A Prospective Resources - as at 30 September 2015

$2.3.$ Development Plans and Forecasts

Table 2-3: Field Development Plan Summary (100%)

$2.4.$ Economic Evaluation

Terms of Reference $3.1$

4. Basis of Assessment

Resource Classification $4.1.$

Table 4-1: Prospective Resources Definition

$4.1.1.$ Chance of Discovery

Licence History and Status 5.

$5.1.1.$ Licence Status

$5.1.2.$ Exploration History

Regional Setting 6.

$6.1.$ Petroleum System

$6.1.1.$ Structure of the Alasehir Basin

$6.1.2.$ Stratigraphy of the Alasehir Basin

Alasehir Formation

Adala Formation

Hamamdere Formation

Kaletepe Formation

Quaternary alluvium

$6.1.3.$ Trap

$6.1.4.$ Source

$6.1.5.$ Reservoir

6.1.6. Seal

Contingent Resources $7.$

$7.1.$ Sarikiz Oil Field

$7.1.1.$ Seismic Interpretation

$7.1.2.$ Depth Conversion

$7.1.3.$ Mapping

$7.1.4.$ RISC Petrophysical Interpretation

$7.1.5.$ Well Test Results

$7.1.6.$ Volumetrics

$7.1.6.1.$ Approach

$7.1.6.2.$ Gross Rock Volume

Area and net pay

$7.1.6.3.$ Reservoir and Fluid Parameters

$7.1.6.4.$ Recovery Factor

$7.1.6.5.$ Summary of Volumetric Input Parameters

Table 7-2: Volumetric Inputs for Sarikiz Oil Field

$7.1.6.6.$ Contingent Resources

$7.1.7.$ Well Spacing and Recovery

$7.2.$ Alasehir Oil Field

$7.2.1.$ Seismic Interpretation

$7.2.2.$ Depth Conversion

$7.2.3.$ Mapping

$7.2.4.$ Well Test Results

$7.2.5.$ Volumetrics

$7.2.5.1.$ Approach

$7.2.5.2.$ Gross Rock Volume

Area and net pay

$7.2.5.3.$ Reservoir and Fluid Parameters

$7.2.5.4$ Recovery Factor

Summary of Volumetric Input Parameters $7.2.5.1$

Table 7-5: Volumetric Inputs for Alasehir Oil Field

Contingent Resources $7.2.5.2.$

$7.2.6.$ Well Spacing and Recovery

Development Plans and Forecasts 8.

GALAN LITHIUM LIMITED Capital/Financing Update 2015