GENEL ENERGY INTERNATIONAL LTD. · Reference: Genel Energy International Ltd. Competent Person’s Report as of December 31, 2015 Taq Taq Field Attention: Prof. Fevzi Gumrah, Subsurface

GENEL ENERGY INTERNATIONAL LTD.

Competent Person’s Report Taq Taq Field

As of December 31, 2015



As of December 31, 2015

Prepared For:

Genel Energy International Ltd. MAICO Building, The Valley Anguilla, British West Indies

TV1 11P

Prepared By: McDaniel & Associates Consultants Ltd.

2200, 255 - 5th Avenue SW Calgary, Alberta

T2P 3G6

April 2016



Table of Contents

1 INTRODUCTION 3

2 CORPORATE SUMMARY 4

2.1 Crude Oil Reserves 6

2.2 Net Present Values of the Reserves 6

2.3 Crude Oil Prospective Resources 7

3 RESERVES AND RESOURCES DEFINITIONS 7

3.1 Resources 7

3.2 Range of Uncertainty 10

3.3 Reserves Categories and Status 10

3.4 Contingent Resource Categories 12

3.5 Prospective Resource Categories 12

4 PROPERTY OVERVIEW 13

5 SOURCE AND QUALITY OF DATA 14

6 REGIONAL GEOLOGY 15

7 GEOLOGY OF THE TAQ TAQ FIELD AREA 16

7.1 Pilaspi Formation 17

7.2 Shiranish Formation 17

7.3 Kometan Formation 18

7.4 Qamchuqa Formation 18

8 GEOLOGICAL MAPPING PETROPHYSICAL PARAMETERS AND OOIP ESTIMATES 19

9 CRUDE OIL RESERVES ESTIMATES 19

10 CRUDE OIL PROSPECTIVE RESOURCES ESTIMATES 21

11 NET PRESENT VALUE ESTIMATES 22

12 PROFESSIONAL QUALIFICATIONS 23



TABLES

GENEL ASSET SUMMARY Table 1

GENEL RESERVES SUMMARY Table 2

GENEL NET PRESENT VALUE SUMMARY OF THE RESERVES Table 3

CRUDE OIL PROSPECTIVE RESOURCES – TAQ TAQ FIELD Table 4

SUMMARY OF RESERVES AND NET PRESENT VALUES Table 5

FORECAST OF PRODUCTION AND REVENUES - PROVED DEVELOPED PRODUCING RESERVES Table 6

FORECAST OF PRODUCTION AND REVENUES - TOTAL PROVED RESERVES Table 7

FORECAST OF PRODUCTION AND REVENUES - PROVED PLUS PROBABLE RESERVES Table 8

FORECAST OF PRODUCTION AND REVENUES - PROVED PLUS PROB. PLUS POSS. RESERVES Table 9

CRUDE OIL RESERVE SUMMARY Table 10

RESERVOIR AND FLUID PROPERTIES Table 11

SUMMARY OF ECONOMIC PARAMETERS Table 12

FORECAST OF CAPITAL COSTS Table 13

SUMMARY OF PRICE FORECASTS Table 14

FIGURES

PROPERTY LOCATION MAP Figure 1

GENEL PSC LOCATION MAP Figure 2

RESOURCE CLASSIFICATION FRAMEWORK Figure 3

RESOURCE SUB-CLASSES BASED ON PROJECT MATURITY Figure 4

TOP STRUCTURE MAP – PILASPI RESERVOIR Figure 5

GROSS OIL THICKNESS MAP – PILASPI RESERVOIR Figure 6

TOP STRUCTURE MAP – SHIRANISH RESERVOIR Figure 7

GROSS OIL THICKNESS MAP – SHIRANISH RESERVOIR Figure 8

TOP STRUCTURE MAP – KOMETAN RESERVOIR Figure 9

GROSS OIL THICKNESS MAP – KOMETAN RESERVOIR Figure 10

TOP STRUCTURE MAP – QAMCHUQA RESERVOIR Figure 11

GROSS OIL THICKNESS MAP – QAMCHUQA RESERVOIR Figure 12

TOTAL FIELD PRODUCTION FORECAST Figure 13

2200, Bow Valley Square 3, 255 - 5 Avenue SW, Calgary AB T2P 3G6 Tel: (403) 262-5506 Fax: (403) 233-2744 www.mcdan.com

April 22, 2016 Genel Energy International Ltd. MAICO Building, The Valley Anguilla, British West Indies TV1 11P Reference: Genel Energy International Ltd. Competent Person’s Report as of December 31, 2015 Taq Taq Field Attention: Prof. Fevzi Gumrah, Subsurface Manager Dear Sir:

1 INTRODUCTION

Pursuant to your request, we have prepared an evaluation of the crude oil reserves and the net present value of these reserves in the Taq Taq Field for the interests of Genel Energy International Ltd. (“Genel”) in the Kurdistan Region of Northern Iraq, as of December 31, 2015.

The future net revenues and net present values presented in this report were calculated using forecast prices and costs using McDaniel & Associates Consultants Ltd. (“McDaniel & Associates”) opinion of future crude oil prices at January 1, 2016 and were presented in United States dollars. The reserves and resource estimates and future net revenue forecasts have been prepared in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System.

This evaluation was prepared during the period from December 2015 to April 2016 and was based on technical and financial data to the end of December 2015. However, some recent water level measurements acquired in January and February 2016 were also considered. Genel has provided McDaniel & Associates with written representation that all technical, financial and ownership information relevant to our opinion has been provided and that no new data or information has been acquired up to the date of this report which might materially impact our opinions in this report. All of the basic information employed in the preparation of this report was obtained from Genel.

Genel Energy International Ltd. Page 4 Competent Person’s Report – Taq Taq Field April 22, 2016

2 CORPORATE SUMMARY

Genel has an interest in the Taq Taq Production Sharing Contract (“PSC”) in Iraq. A general location map of this PSC and the oil transportation system within and out of Iraq are shown in Figure 1 below:

Figure 1 – Property Location Map

A summary of Genel’s interest in the PSC is presented in Table 1 below:

Oil Field Country Operating Company

Contract Type

Working Interest

Paying Interest

Contract Expiry Date

Area (sq.km)

Taq Taq Iraq TTOPCO

Production Sharing Contract 44%

55% Feb 26, 2033 951

Table 1 - Genel Asset Summary


A more detailed map of the Kurdistan Area of Iraq showing the location of the Taq Taq PSC is presented in Figure 2 below. The blocks shown in red include the other Genel blocks within Kurdistan.

Figure 2 - Genel PSC Location Map (Source: The Oil & Gas Year Book - 2014)


2.1 Crude Oil Reserves

Crude oil reserves have been assigned to the Taq Taq Field. The property gross and Genel’s gross and net working interest share of the crude oil reserves as of December 31, 2015 are presented in Table 2 below:

Crude Oil Reserves at December 31, 2015, Mbbl

Proved

Producing

Proved

Developed Non-

Producing

Proved Developed

Proved Undeveloped

Total Proved Probable

Total Proved

& Probable Possible

Total Proved,

Probable &

Possible Property Gross 55,177 - 55,177 4,810 59,987 111,861 171,848 244,528 416,376 Company Gross (1) 24,278 - 24,278 2,116 26,394 49,219 75,613 107,592 183,205

Company Net (2) 8,561 - 8,561 795 9,356 14,168 23,524 23,410 46,935

(1) Company gross reserves are based on Genel’s 44 percent working interest share of the property gross reserves (2) Company net reserves are based on Genel’s share of the Cost Oil and Profit Oil revenues.

Table 2 - Genel Reserves Summary

Although the Taq Taq Field already has 28 wells drilled and has produced more than 180 MMbbl to date, there is still a very large uncertainty in the oil reserves. This is mainly because the reserves are dependent on the Shiranish Formation fracture porosity in the un-swept portion of the reservoir which is very difficult to estimate even when, as is the case with the Taq Taq Field, a lot of data has been gathered and analysis undertaken.

2.2 Net Present Values of the Reserves

The net present values of the crude oil reserves were based on future production and revenue analyses. Genel’s share of the net present values of the reserves, based on forecast prices and costs as of December 31, 2015, are presented in Table 3 below:

Net Present Values at December 31, 2015, US$MM (1) (2) (3)

Discounted At 0% 5% 10% 12.5% 15% 20%

Proved Producing Reserves 163 151 140 136 132 124 Proved Developed Non-Producing Reserves - - - - - -

Proved Developed Reserves 163 151 140 136 132 124 Proved Undeveloped Reserves 13 12 12 11 11 11 Total Proved Reserves 176 163 152 147 143 134 Probable Reserves 426 323 254 228 205 170 Proved + Probable Reserves 602 486 406 375 348 305 Possible Reserves 855 595 434 376 328 256 Proved + Probable + Possible Reserves 1,457 1,081 840 751 676 561

(1) Based on forecast prices and costs at December 31, 2015 (see Table 14 at the end of the report). (2) Interest expenses and corporate overhead, etc. were not included. (3) The net present values may not necessarily represent the fair market value of the reserves.

Table 3 - Genel Net Present Value Summary of the Reserves


2.3 Crude Oil Prospective Resources

Crude oil prospective resources have been assigned to the Qamchuqa Formation within the Taq Taq Field. The property gross and Genel’s gross working interest share of the crude oil prospective resources as of December 31, 2015 are presented in Table 4 on an unrisked and risked basis.

Chance of Risked (2)

Prospective Resources – Unrisked (1) Technical Chance of Resources

Low Best Est. Mean (3) High Success Develop. Mean

Mbbl Mbbl Mbbl Mbbl % % Mbbl

Property Gross 3,252 19,512 20,487 39,024 30 90 5,532

Company Gross (4) 1,431 8,585 9,014 17,170 30 90 2,434

(1) There is no certainty that any portion of the prospective resources will be technically feasible to produce or economically viable to develop.

(2) These are fully risked prospective resources that have been risked for chance of technical success and for chance of development. Chance of technical success is difficult to estimate but depends on being able to directly produce oil below the fracture FWL.

(3) Swanson’s Mean. (4) Company gross prospective resources are based on Genel’s 44 percent working interest share of the property gross

prospective resources.

Table 4 – Qamchuqa Formation Crude Oil Prospective Resources

3 RESERVES AND RESOURCES DEFINITIONS

The definitions employed in this evaluation conform to the 2007 Petroleum Resource Management System (“PRMS”) jointly published by the Society of Petroleum Engineers (“SPE”), World Petroleum Council (“WPC”), American Association of Petroleum Geology (“AAPG”) and the Society of Petroleum Evaluation Engineers (“SPEE”). A summary of those definitions is presented below:

3.1 Resources

The term “resources” is intended to encompass all quantities of petroleum naturally occurring on or within the Earth’s crust, discovered and undiscovered (recoverable and unrecoverable), plus those quantities already produced. Further, it includes all types of petroleum whether currently considered “conventional” or “unconventional.”

The resources classification framework is summarized in Figure 3 and a summary of the definitions are given below.


Figure 3 – Resource Classification Framework

The “Range of Uncertainty” reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the “Chance of Commerciality”, that is, the chance that the project that will be developed and reach commercial producing status.

The quantities estimated to be initially-in-place are defined as Total Petroleum-initially-in-place, Discovered Petroleum-initially-in-place and Undiscovered Petroleum-initially-in-place, and the recoverable portions are defined separately as Reserves, Contingent Resources, and Prospective Resources. Reserves constitute a subset of resources, being those quantities that are discovered (i.e. in known accumulations), recoverable, commercial and remaining.

It is also useful within the resources classification reporting system to subdivide the chance of commerciality axis according to project maturity. As illustrated in Figure 4, development projects (and their associated recoverable quantities) may be sub-classified according to project maturity levels and the associated actions (business decisions) required to move a project toward commercial production.

Production

Reserves

ProvedProved

plus Probable

Proved plus

Probable plus

Possible

Contingent Resources

Unrecoverable

Prospective Resources

Low Estimate

Best Estimate

High Estimate

Unrecoverable

Range of Uncertainty

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1P 2P 3P

1C 2C 3C


Figure 4 – Resource Sub-classes based on Project Maturity

A description of the recoverable portions of the resource classification framework is given below.

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 categorized 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.

Contingent Resources

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

Production Project Maturity Sub-classes

Reserves On ProductionApproved for DevelopmentJustified for

Development

Contingent Resources Development PendingDevelopment

Unclarified or On HoldDevelopment Not

Viable

Unrecoverable

Prospective Resources Prospect

Lead

Play

Unrecoverable

Range of Uncertainty

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Prospective Resources

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.

3.2 Range of Uncertainty

The range of uncertainty of the recoverable and/or potentially recoverable volumes may be represented by either deterministic scenarios or by a probability distribution. 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 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

• There should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

• There should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

When using the deterministic scenario method, typically there should also be low, best, and high estimates, where such estimates are based on qualitative assessments of relative uncertainty using consistent interpretation guidelines. Under the deterministic incremental (risk-based) approach, quantities at each level of uncertainty are estimated discretely and separately.

These same approaches to describing uncertainty may be applied to Reserves, Contingent Resources, and Prospective Resources. While there may be significant risk that sub-commercial and undiscovered accumulations will not achieve commercial production, it is useful to consider the range of potentially recoverable quantities independently of such a risk or consideration of the resource class to which the quantities will be assigned.

3.3 Reserves Categories and Status

For Reserves, the general cumulative terms low/best/high estimates are denoted as 1P/2P/3P, respectively. The associated incremental quantities are termed Proved, Probable and Possible. Reserves are a subset of, and must be viewed within context of, the complete resources classification system.


Proved Reserves

Proved Reserves (1P) 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 percent probability that the quantities actually recovered will equal or exceed the estimate.

Probable Reserves

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate 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 percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves

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) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10 percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

Reserves status categories define the development and producing status of wells and reservoirs.

Developed Reserves

Developed Reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.


Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-producing Reserves

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or, (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

Undeveloped Reserves

Undeveloped Reserves are expected quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects.

3.4 Contingent Resource Categories

For Contingent Resources, the general cumulative terms low/best/high estimates are denoted as 1C/2C/3C respectively. No specific terms are defined for incremental quantities within Contingent Resources.

3.5 Prospective Resource Categories

For Prospective Resources, the general cumulative terms low/best/high estimates apply. No specific terms are defined for incremental quantities within Prospective Resources.


4 PROPERTY OVERVIEW

The Taq Taq Field is located within the Kurdistan Region of Iraq approximately 60 kilometres northeast of the giant Kirkuk oil field and 85 kilometres southeast of the City of Erbil. The Taq Taq Field was discovered in 1978 with the TT-01 exploration well and followed by two further wells, TT-02 in 1978 and TT-03 in 1981, all in the Crestal Area of the Taq Taq structure. Very little activity occurred in the field until the TT-01 and TT-02 started producing relatively minor volumes of oil for local use in 1995.

The initial Taq Taq Production Sharing Agreement (“PSA”) was signed by Genel and the Kurdistan Regional Government (“KRG”) in July 2002 and was amended on January 20, 2004 to include additional work obligations. The PSA was amended in November 2006 to add the Kewa Chirmila Exploration Block. The Taq Taq and Kewa Chirmila blocks are designated as sub-areas in the PSC and unsuccessful wells in Kewa Chirmila can be written off against revenues from Taq Taq. It should be noted, however, that no reserves or resources were assigned to the Kewa Chirmila Area in this report.

A Production Sharing Contract (“PSC”) was then signed on February 26, 2008 to modify the fiscal terms. The PSC has typical obligations with a state royalty of 10 percent and a contractor share of profit oil ranging from 15.6 to 30 percent. The First Amendment Agreement signed in May 2009 states that Genel is obligated to pay 30 percent of its profit oil as a capacity building payment to the government.

Genel entered into a farm in with Addax Petroleum Corp. (“Addax”) in July 2005 which assigned Addax a 30 percent working interest and leaving Genel with a 70 percent working interest. A further farm-in was agreed in November 2006, whereby Addax’s interest increased from 30 to 45 percent and Genel’s interest dropped to 55 percent. Addax was then acquired by China Petrochemical Corporation (“Sinopec Group”) in June 2009. Genel and Addax formed the TTOPCO operating company in 2006 to operate the field, which it still does today. TTOPCO is owned 55 percent by Genel and 45 percent by Addax.

Payment and consideration terms under the 2005 and 2006 farm-in agreements were aggregated into one farm-in consolidation agreement signed by Genel and Addax in June 2010. As consideration for the farm-ins Addax agreed (i) to carry a portion of Genel’s costs on the Taq Taq Field and (ii) agreed to pay a royalty to Genel equal to 2.5 percent of Addax’s share of cost oil and profit oil for the remaining life of the field. US $68.2m of costs carried by Addax were to be repaid by Genel by offsetting this amount against future royalty payments. When the US $68.2m has been recovered by Addax, the 2.5 percent royalty will be payable in cash by Addax to Genel.

Following the commencement of commercial sales, the Government exercised the right at no cost to back in for a 20 percent carried working interest which effectively reduced Genel’s working interest in revenues from 55 to 44 percent.

A two dimensional (“2D”) seismic program was completed on the Taq Taq Field in 2006 and extended over the rest of the block including the Kewa Chirmila Area in 2007. Also in 2007, a three dimensional (“3D”) seismic survey was acquired over the Taq Taq Field. Drilling resumed


in the Taq Taq Field in 2006 and by end 2014, 23 new wells had been drilled resulting in a field production rate of over 100,000 bopd. During 2015 a further two wells, TT-24 and TT-28 were drilled with TT-24 as a horizontal well. An exploration well in the Kewa Chirmila Area was drilled in 2009 and did not encounter any hydrocarbons.

Until June 2009, Taq Taq production was being sold to local markets up to a maximum rate of 15,000 bopd. After then production has mostly been sold both to the export market and local markets. In 2014, a new Kurdish Regional Government pipeline became operational allowing export all the way to the Turkish port of Ceyhan. Although there had been a problem receiving export payments this has recently been resolved and Genel is now receiving regular payments. Genel expects the majority of future production to be sold to export markets. After the effective date of this report Genel announced they had agreed terms with the KRG to receive the same net-back oil price regardless of whether it ultimately went to the domestic or export market.

The production facility has been expanded since an early production facility with a loading facility was completed in 2008 with a capacity of about 15,000 bopd. Currently, the central processing facility can handle up to 120,000 bopd and 15,000 bwpd. Final commissioning of the second central processing facility (CPF-2) is underway, following which field processing capacity will be 150,000 bopd and 45,000 bwpd.

5 SOURCE AND QUALITY OF DATA

Essentially all of the basic information employed in the preparation of this report was obtained from Genel’s files. McDaniel & Associates traveled to Genel’s offices in Ankara, Turkey to collect data and discuss the evaluation with Genel’s technical staff.

The data available for the evaluation consisted of digital logs for 26 out of the 28 wells in the Taq Taq Field. The well TT-03 doesn’t have a log, but wasn’t drilled deep enough to penetrate the main oil bearing horizons, so wasn’t considered to be important. The logs for the wells drilled from 2006 to 2015 are good quality modern logs, run either by a Chinese logging company using western style tools (up to and including well TT-17) or western logging companies such as Schlumberger and Weatherford. Along with digital logs computer processed interpretation reports of the logs were also provided. Many of the wells had FMI and micro-resistivity logs available to investigate the fracture system in the formations. A Reservoir Saturation Tool (“RST”) log was also provided for well TT-12 which helps evaluate the matrix oil saturation in flushed fractured reservoirs.

Core data has been taken in fourteen of the Taq Taq Field wells. Detailed sedimentological, structural and stratigraphic studies performed by Robertson on nineteen of the wells and a 2014 petrography study by Oolithica Geoscience Ltd. of Shiranish cuttings and core samples from five wells were provided for review. Mercury injection capillary pressure (“MICP”) measurements made during 2015 by Core Laboratories (“Core Lab”) on 19 core plugs taken from the Shiranish Formation in wells TT-20, TT-21, TT-23 and TT-27 were also made available.


General well file data, log data and log interpretation reports, test reports, and well coordinates were provided for all of the wells. PVT data was provided for three wells as well as production information for the two older wells.

A complete set of the digital seismic data including interpretation results was provided for review. Both the 2D and 3D seismic projects including interpretation of the main horizons were provided for review. The 3D seismic interpretation was considered to be reasonable and was used for structural mapping. The seismic and log data for the new wells are of excellent quality and prepared under western standards. In our opinion, the data available for this evaluation was of excellent quality and sufficient to provide confident estimates of the reserves and revenue forecasts.

During the visit to Genel’s office in Ankara, McDaniel & Associates reviewed the work undertaken by Genel to build an integrated subsurface model of the field in Schlumberger’s Petrel and Eclipse software. The Petrel model incorporated a discrete fracture network model which was populated using both well and seismic data.

6 REGIONAL GEOLOGY

The Taq Taq Field is located within in the Kurdistan Region of Iraq approximately 60 kilometres northeast of the giant Kirkuk oil field and 85 kilometres southeast of the City of Erbil. The Kirkuk oil field was discovered in 1927 and has produced more than 11 billion barrels. It is a huge compressed anticlinal structure more than 96 kilometres long and three to four kilometres wide.

The Taq Taq Field is within the Zagros Sedimentary Basin which is a world-class hydrocarbon province located on the northeastern margin of the Arabian Platform. This Basin is located along the Zagros thrust belt and covers an area of some 200,000 square kilometres. It extends from the Taurus thrust zone in the north (Turkey) to the Arabian Gulf and Oman in the south. The Basin is a typical foreland compressional basin formed by the collision of the Afro-Arabian and Iranian plates in Late Cretaceous and Cenozoic times.

The Zagros Basin is characterized by a series of sub parallel faults, compressed anticlines and adjoined synclines along the Zagros mountain system. Deposition within the Basin is interpreted as the product of four major geotectonic events:

• Opening of the Neo-Tethys ocean in late Permian–Triassic time

• Expansion of the Basin in Jurassic and early Cretaceous time when massive carbonate sedimentation occurred in the Basin.

• Beginning of burying and closing of the Basin in late Cretaceous Turonian time when the Iranian platform collided with the Arabian plate.

• Tectonic movement and uplift during Alpine orogeny and forming mountains, folds and thrusts.


The late Permian and Triassic rocks were deposited in relatively stable shelf conditions and consist of shallow water carbonates with minor evaporate and clastic content. Jurassic sediments were also deposited in the shelf environment and consist primarily of carbonates ranging from deep water mudstones-wackestones to shallow water packstones-grainstones interbedded with supra-tidal carbonates and anhydrites.

From middle Jurassic to late Cretaceous time the carbonate platform was divided into several semi-isolated basins. Clastic sedimentation dominated the western part of the area. Several uplifts and erosional periods occurred in Cretaceous time. Carbonate deposition was dominant during Mesozoic time in the Zagros Basin area.

During the Alpine orogeny, Neo-Tethys oceanic crust was overthrusted on to Arabian passive continental margin and dramatically changed the structural and stratigraphic regime of the area. A northwest southeast trending foredeep was developed along the rising orogen. While flysch deposits accumulated along the thrust zone, deeper shelf pelagic limestone and marls were deposited towards the west.

During Paleocene–Early Eocene time, a deep open marine basin was oriented along the thrust belt in northern Iraq. Carbonate and evaporate sediments were deposited in the central and southwestern parts of the basin and coarse clastic rocks were deposited in the northeastern areas.

Folding and uplift of the Zagros Mountains had begun in early Miocene time. The upper Miocene and Pliocene rocks have syn-orogenic and post-orogenic genesis.

According to published information, the main source rocks in the area are in the Jurassic Sargelu and Naokelekan formations. Additional hydrocarbon source rocks are found in the Cretaceous Chiagara and Balambo formations and Triassic Kurra Chine Formation. Hydrocarbon generation and migration in the Zagros Basin began during the late Paleogene–Neogene folding and faulting. Faults and fracture development created vertical migration paths to hydrocarbons, but also may have also resulted in some hydrocarbon loss. The lack of structural fragmentation in Mesozoic and Cenozoic rocks allowed extensive lateral migration from the kitchen to existing structures. The main hydrocarbon kitchen was likely located to the west and southwest of the Taq Taq Area.

7 GEOLOGY OF THE TAQ TAQ FIELD AREA

The Taq Taq Field consists of a simple compressed anticline structure. The structure was initially mapped based on the surface outcrop data. The Taq Taq Area was covered by 2D seismic in 2005 and 2006 and a total of 11 seismic lines (170 linear kilometres) were acquired by the Canadian company, Terra Seis International. The 2006 2D seismic interpretation confirmed the presence of a four way closed anticline structure in the Mesozoic and younger deposits. Several low displacement faults also were interpreted in the area. The anticline axis is oriented in the northwest to southeast direction, parallel to the main Zagros Basin trend. The 3D seismic acquired in 2007 confirmed the interpretation of the 2D seismic.


The deepest well in the field is TT-22 which drilled in 2014 a sedimentary section to a depth of 4,613 metres (3,947.7 metres subsea (“m ss”)), penetrating the Triassic Kurra Chine Formation (A, B and C members). The well was subsequently sidetracked and put on production as a Cretaceous producer.

There are four oil bearing zones that have been discovered in the Taq Taq Field, one in the Oligocene Pilaspi Formation and three in the Upper Cretaceous Shiranish, Kometan and Qamchuqa formations. The oil in Pilaspi Formation is relatively heavy with an API gravity of 25.7 degrees and the Cretaceous reservoirs contain a lighter, very low gas oil ratio oil with an API gravity of 48.5 degrees.

An initial estimated oil-water contact in the Cretaceous reservoirs was not interpreted from the log analysis but was estimated by McDaniel & Associates from RFT test data and highest known water/lowest known oil data to be at a depth of 1,510 m subsea. (Genel estimates a slightly deeper oil-water contact at 1,515 m ss.) All of the Cretaceous oil-bearing formations are considered to be in communication through the fault and fracture system.

A discussion of the reservoir properties for the main oil-bearing formations in the Taq Taq Field is presented below.

7.1 Pilaspi Formation

The Eocene age Pilaspi Formation is a regionally productive oil reservoir. The Pilaspi Formation in the Taq Taq Field has a gross thickness is in the range of 50 to 100 metres and consists of limestone and dolomites. The Taq Taq Pilaspi pool was discovered by the TT-01 well and is producing from the TT-02 well. The pool appears to be a simple anticline which McDaniel & Associates interprets to have an original oil-water contact at a depth of 45 metres above sea level. (Genel estimates a shallower original oil water contact at 58.6 metres above sea level). A structure map and gross oil thickness map for the Pilaspi Formation are presented in Figures 5 and 6 at the end of the report.

7.2 Shiranish Formation

The Shiranish Formation is a regionally developed hydrocarbon-bearing reservoir. The gross formation thickness is in the range of 250 to 300 metres and consists of shaley limestone–wackstone and packstone in an argillaceous matrix. The upper part of the formation consists of marly limestone.

The reservoir properties were estimated based on the wireline log for all of the wells and the available core data. In 2014, Oolithica performed a detailed petrography study for the Shiranish Formation based on cuttings and core samples from the TT-04, TT-05, TT-06, TT-16 and TT-19z wells and in 2015 Core Lab conducted MICP measurements on 19 core plugs from the Shiranish Formation in wells TT-20, TT-21, TT-23 and TT-27. Based on these studies it was concluded that the majority of the Shiranish Formation is tight and lacks any matrix porosity. In some intervals any original matrix porosity is likely enhanced by micro-fractures and small scale fault networks but in the absence of fractures, the Shiranish Formation is considered as mostly non-reservoir rock.


McDaniel & Associates has included the possibility of some effective matrix porosity in the 3P case; a net-to-gross of 2.6 percent and a porosity of 8.4 percent were assigned.

The Shiranish Formation is reported to be Cretaceous late Campanian to Maastrichtian age. The seal for the Shiranish and lower formations is provided by clastic and carbonates layers of the Kolash Formation.

An oil-water contact was not encountered in the wells and was assumed to be the same as the oil-water contact in the Qamchuqa Formation. Structure and gross oil thickness maps for the Shiranish Formation are presented in Figures 7 and 8 at the end of the report.

7.3 Kometan Formation

The Kometan Formation is a regionally developed tight carbonate formation. It consists of light brown to white, pyritic, highly glauconitic limestone and dolomites. The dolomitization was interpreted to be developed locally in the area of the TT-05, TT-08 and TT-20 wells. The formation thickness is in the range of 70 to 120 metres. The carbonates are generally very clean with a shale volume less than 15 percent. There is an unconformity at the bottom of the formation and the top of the formation is unconformable with the Shiranish Formation.

The Kometan Formation is reported to be Cretaceous early Turonian to early Campanian age. The reservoir properties were estimated based on the wireline log and core data from all of the available wells. The average porosity is in the range from 5 to 15 percent in the permeable dolomitic zones. The intervals with only original matrix porosity are almost impermeable. The main productive intervals are in zones with extensive fracture development. In intervals with an absence of fracture porosity, the formation doesn’t flow as indicated by test data in the TT-05 well.

An oil-water contact was not encountered in the wells and the Kometan was assumed to have the same oil-water contact as the Qamchuqa Formation. The Kometan Formation structure map and gross oil thickness map are shown in Figures 9 and 10 at the end of the report.

7.4 Qamchuqa Formation

The Qamchuqa is a regionally developed oil-bearing formation. This formation was deposited in a shallow marine environment and consists of dolomite and limestone. The upper 100 to 150 metres consist of mostly dolomite, which is progressively replaced by limestone with depth. The maximum penetrated gross formation thickness was 582 metres in the TT-01 well and the net oil saturated thickness 80.6 metres in the same well. The trap is interpreted to be a simple anticline and contains oil underlain by water over the full pool area. The Qamchuqa Formation is reported to be Cretaceous Albian age in the upper part and Cretaceous Aptian age in the lower part.

The main porosity types in the Qamchuqa Formation are vuggy and inter-crystalline associated with diagenetic dolomitization and enhanced by fracturing. Core from the Qamchuqa formation was taken in seven wells (TT-06, TT-07, TT-08, TT-09, TT-10 TT-13 and TT-16). The total porosity is usually in the range of 10 to 16 percent.


McDaniel & Associates has estimated an oil-water contact from RFT test data and highest known water/lowest known oil data to be at a depth of 1,510 m ss and it was assumed the Shiranish and Kometan formations will have the same oil-water contact. Structure and gross oil thickness maps for the Qamchuqa Formation are presented in Figures 11 and 12 at the end of the report.

8 GEOLOGICAL MAPPING PETROPHYSICAL PARAMETERS AND OOIP ESTIMATES

Original oil-in-place (“OOIP”) estimates were based on the structure and gross oil thickness maps presented in Figures 5 to 12 at the end of the report for each of the four zones and the petrophysical parameters presented in Table 10 at the end of the report.

The petrophysical parameters were based on log interpretations for the wells that penetrated the zone. Intervals that were interpreted to be fractured were excluded when estimating matrix porosity. The porosities for the matrix zones were based on log interpretations using a porosity cutoff of five percent for the Pilaspi, Shiranish and Kometan and seven percent for the Qamchuqa Formation. The water saturations were also estimated from log interpretations.

The fractured intervals were then assumed to have the same average matrix porosity and net-to-gross as the non-fractured intervals. The fracture porosity for the Kometan and Qamchuqa formations of 0.57 percent was based on the cumulative production to date and the apparent rise in the fracture oil-water contact. The fracture porosity for the Shiranish Formation was estimated to range from 0.21 in the 1P case, to 0.38 in the 2P case and to 0.70 percent in the 3P case. The 1P case was based on a conservative interpretation of the performance to date and the 3P case was based on regional experience; the 2P estimate assumes the fracture porosity is distributed log normally. Water saturations in the fractures were assigned a value of 10 percent.

The gross rock volume in the reserves cases was based on total pool area as planimetered from the gross oil thickness maps for each zone. The resulting petrophysical and volumetric parameters and the OOIP estimates for each zone are summarized in Table 10 at the end of the report.

9 CRUDE OIL RESERVES ESTIMATES

The crude oil reserves were based on volumetric, reservoir simulation and performance derived estimates considering all available data including production data, observed movement in the oil-water contact, test data, structural and net pay interpretations, reservoir and fluid characteristics, performance of analogous reservoirs and economics of development. A summary of the calculation of the reserves estimates for each zone is presented in Table 10 and a summary of various reservoir and fluid properties in Table 11 at the end of the report.

A summary of the total Taq Taq Field reserves by reserves category are presented in Table 5 at the end of the report.

The crude oil reserves estimates were based on volumetrically calculated OOIP estimates (as described in the Section 8 above) and estimated recovery factors. In all the cases, the vast majority of the Cretaceous oil reserves are associated with recovery from the Shiranish Formation fracture system; the fracture oil-water contact is estimated to be above the top of the Kometan Formation and further matrix recovery from all the formations is expected to be minimal. The fracture oil recovery factor was estimated to be 80 percent taking into account some of the fracture system may be bypassed.


The fracture oil-water contact is interpreted to be different from the matrix oil-water contact. Based on the RST log interpretation for well TT-12, the matrix oil-water contact in Qamchuqa Formation is estimated to be 1,374 m ss. Some future potential may be associated with the undrained oil in the matrix below the fracture oil-water contact and this is discussed in Section 10.

As discussed in Section 7.2, the Shiranish Formation fracture porosity for the 1P case was derived using performance analysis. If the oil recovery is plotted against the rise in the fracture oil-water contact, the relationship can be modelled based on an area-depth relationship for the structure, the fracture porosity, the likely moveable oil fraction and the sweep efficiency. Static pressure gradient surveys (“SGS”) run in wells over the life of the field have allowed the rise in the oil-water contact in the fracture system to be estimated.

Until recently, it was unclear how much variation there was across the field in the fracture oil-water contact as most of the measurements were taken in well TT-10 on the crest of the structure. Recent measurements, including some after the effective date of the report, have confirmed that the fracture oil-water contact is not uniform and appears to range from 1,200 m ss on the crest to 1,300 m ss on the flanks. Furthermore, in wells producing at high rate, there is evidence that the water level is dynamically raised at the well relative to the fracture oil-water contact in offsetting lower rate wells. One possible explanation is that water is being preferentially pulled up through the faults and fracture corridors and shut-in times prior to running a SGS are too short to allow the water to drain back into the matrix and micro-fracture system and so the measured water level is not representative of the fracture oil-water contact over a wider area.

McDaniel & Associates plotted the fracture oil-water contact measurements versus the cumulative oil production and attempted to analytically match an average oil-water contact midway between the measurements on the flanks and the crest. The match is very sensitive to the assumed fracture porosity which is why the method was used to estimate this uncertain parameter. The match can also be extrapolated to the crest of the structure to determine the estimated ultimate recovery (“EUR”) and the reserves. The 1P reserves were based on this analysis and are estimated as 240 MMbbl corresponding to a Shiranish fracture porosity of 0.21 percent. The PDP reserves were assumed to be 235 MMbbl with proved undeveloped (“PUD”) reserves of five MMbbl assigned to two wells (most likely sidetracks of TT-27 and TT-28).

The 2P reserves estimates were in part guided by detailed reservoir modelling work Genel is undertaking using Schlumberger’s Petrel and Eclipse software to help quantify the uncertainty in the future performance. The 2P reserves for the Cretaceous were estimated using a fracture porosity of 0.38 percent and the same 80 percent fracture oil recovery factor as used for the 1P case; the 2P case EUR is 349 MMbbl with 166 MMbbl of 2P reserves. Genel discussed the early results of their simulation model and explained the uncertainties within the Shiranish Formation to be incorporated into their model through sensitivity runs. The early results of Genel’s simulation model were taken into account to predict the 2P reserves by McDaniel & Associates under the consideration of the uncertainties within the Shiranish Formation and in particular the likely conservative nature of the existing discrete fracture network model. Genel intends for the simulation model to be regularly updated with the future production performance of the Shiranish Formation.


The 3P reserves for the Cretaceous assume higher fracture porosity, improved fracture oil recovery and some additional matrix oil recovery. The 3P EUR is 589 MMbbl and 3P reserves are 406 MMbbl.

In summary, there is very large uncertainty in the Cretaceous oil reserves which range from 58 MMbbl in the 1P case, to 166 MMbbl in the 2P case and 406 MMbbl in the 3P case. The reason for this is that the Shiranish Formation fracture porosity in the un-swept portion of the reservoir is poorly defined.

The crude oil reserves for the Pilapsi reservoir were estimated in a similar way to the Cretaceous. Historical production from well TT-02 of 1.2 MMbbl has caused a 15 metre rise in the fracture oil-water contact. Based on the geometry of the structure and uniform reservoir parameters the reserves could be as low as 2.4 MMbbl. As there are now four wells capable of production it is hoped that the sweep can be improved and 2P reserves of 5.5 MMbbl and 3P reserves of 10.2 MMbbl were assigned based on drilling one probable well and one possible well. Assigned recovery factors are lower than for the Cretaceous reservoirs because the oil is heavier (25.7 API compared to 48.5 API).

10 CRUDE OIL PROSPECTIVE RESOURCES ESTIMATES

The RST log run in well TT-12 has established there is oil remaining in the Qamchuqa Formation matrix below the fracture oil-water contact. Genel intends to implement certain projects in 2016 to recover this bypassed oil, but in our opinion these have associated technical risk and as such are classified as prospective resources. These crude oil prospective resources are presented in Table 4 within Section 2.3 on an unrisked and risked basis.

As a first method to develop the prospective resources, Genel intends to run an electric submersible pump below the fracture oil-water contact in well TT-12 to attempt to recover the remaining oil in the Qamchuqa Formation identified from the RST log. McDaniel & Associates is of the opinion that attempting to recover this oil using viscous forces in the likely presence of high permeability fractures is unproven. Genel is also considering sidetracking existing wells using coiled tubing to drill small diameter horizontal multi-laterals, oriented to try and avoid the fractures within the Qamchuqa Formation. Given both these methods may not technically work the resources are classified as prospective resources.

The prospective resources assume the overall Qamchuqa Formation matrix recovery factor will range from 12.5 percent in the low case, to 25 percent in the best estimate case and to 30 percent in the high case. The unrisked prospective resources were then estimated by applying these recovery factors to the OOIP and then subtracting the reserves. The high case also assumes an increase in the high case OOIP of 50 percent.


11 NET PRESENT VALUE ESTIMATES

The net present values of the crude oil reserves were based on future production and revenue analyses. All of the revenues and costs presented in this report were presented in United States (“US”) dollars. A summary of the production and revenue forecasts for the PDP, 1P, 2P and 3P reserves cases are presented at the end of the report in Tables 6 to 9. A summary of the resulting net present value estimates for the Taq Taq Field are presented Table 5 at the end of the report.

The price for oil sales were based on the McDaniel & Associates January 1, 2016 Brent price forecast less an allowance for transportation to sales markets and any quality discounts, a summary of the price forecasts is presented in Table 14 at the end of the report. Genel estimates that the total differential for the 48.5 API, Cretaceous oil will be $5.0/bbl (made up of 1.0$/bbl for quality differences and 4.0$/bbl from transportation and handling costs). Similarly, Genel estimates the total differential for the 25.7 API, Pilaspi oil will be $11.0/bbl (made up of 7.0$/bbl for quality differences and 4.0$/bbl from transportation and handling costs). McDaniel & Associates considers these differentials to be reasonable. After the effective date of this report, Genel has agreed with the KRG that their oil sales during 2016 will be at Brent less $5.0/bbl which, as most of the production will be from the Cretaceous, is in line with this evaluation.

Government share of revenues is through a royalty and cost oil/profit oil fiscal system. Genel will also receive a 2.5 percent consideration from Sinopec once the previously carried costs have been recovered by Addax. Operating and capital costs were based on a combination of Genel budgets and McDaniel & Associates estimates and are summarized in Tables 12 and 13 at the end of the report. The G&A plus fixed operating costs presented in Table 12 include a portion of the G&A, HSE and security costs as well as the fixed production operating costs. From an accounting perspective Genel treats 50 percent of the fixed costs that are not directly production related as capital costs but this approach has not been adopted here. For this reason the McDaniel & Associates estimate of unit operating cost for 2016 of US $2.3/bbl in the 2P case is slightly higher than Genel’s own estimate which is forecast to be less than US $2/bbl.

Production and revenue forecasts were prepared for the proved developed producing, total proved, proved plus probable and proved plus probable plus possible categories. The production forecasts are presented in graphical format in Figure 13. The net present value estimates for the probable reserves were calculated by subtracting the proved net present values from the proved plus probable net present values. The net present value estimates for the possible reserves were calculated by subtracting the proved plus probable net present value from the proved plus probable plus possible net present value.


12 PROFESSIONAL QUALIFICATIONS

McDaniel & Associates Consultants Ltd. has over 60 years of experience in the evaluation of oil and gas properties. McDaniel & Associates is registered with the Association of Professional Engineers and Geoscientists of Alberta (APEGA). Mr. Paul Taylor, Vice President, and Mr. Anatoli Tchernavskikh, Manager International Geology, all with McDaniel & Associates, supervised the preparation of this report. Mr. Taylor has over 25 years of experience in the evaluation of oil and gas properties and Mr. Anatoli Tchernavskikh has in excess of 15 years. All of the persons involved in the preparation of this report and McDaniel & Associates are independent of Genel.

In preparing this report, we relied upon certain factual information including ownership, technical well data, production data, and other relevant data supplied by the Company. The extent and character of all factual information supplied were relied upon by us in preparing this report and has been accepted as represented without independent verification. We have relied upon representations made by the Company as to the completeness and accuracy of the data provided and that no new data has come to light that may result in a material change to the evaluation of the reserves and prospective resources presented herein.

This report was prepared by McDaniel & Associates Consultants Ltd. for the use of Genel Energy International Ltd. under the terms of our engagement agreement dated November 25, 2015. We reserve the right to revise any estimates provided herein if any relevant data existing prior to preparation of this letter was not made available, if any data between the effective date of the assessment and the date of this letter were to vary significantly from that forecast, or if any data provided was found to be erroneous.

Sincerely, McDANIEL & ASSOCIATES CONSULTANTS LTD. APEGA PERMIT NUMBER: P3145 ______________________________ ______________________________ P. M. Taylor, CEng MEI, P. Eng. A. V. Tchernavskikh, P. Geol. Vice President Manager, International Geology PMT/AVT:jep [15-0370]

Genel Energy International Ltd. Table 5

Taq Taq Field - Iraq

Summary of Reserves and Net Present ValuesEffective December 31, 2015

Summary of Reserves (1)

Total Crude Oil Reserves

Property Company Company

Gross Gross Net

Reserve Category Mbbl Mbbl Mbbl

Proved Developed Producing Reserves 55,177 24,278 8,561

Proved Developed Non-Producing Reserves - - -

Proved Developed Reserves 55,177 24,278 8,561

Proved Undeveloped Reserves 4,810 2,116 795

Total Proved Reserves 59,987 26,394 9,356

Probable Reserves 111,861 49,219 14,168

Proved + Probable Reserves 171,848 75,613 23,524

Possible Reserves 244,528 107,592 23,410

Proved + Probable + Possible Reserves 416,376 183,205 46,935

Summary of Company Share of Net Present Values

$MM US Dollars

Reserve Category 0.0% 5.0% 10.0% 12.5% 15.0% 20.0%

Proved Developed Producing Reserves 163 151 140 136 132 124

Proved Developed Non-Producing Reserves - - - - - -

Proved Developed Reserves 163 151 140 136 132 124

Proved Undeveloped Reserves 13 12 12 11 11 11

Total Proved Reserves 176 163 152 147 143 134

Probable Reserves 426 323 254 228 205 170

Proved + Probable Reserves 602 486 406 375 348 305

Possible Reserves 855 595 434 376 328 256

Proved + Probable + Possible Reserves 1,457 1,081 840 751 676 561

Summary of Company Share of Unit Values

$/bbl US Dollars

Reserve Category 0.0% 5.0% 10.0% 12.5% 15.0% 20.0%

Proved Developed Producing Reserves 6.72 6.21 5.79 5.60 5.42 5.11

Proved Developed Non-Producing Reserves - - - - - -

Proved Developed Reserves 6.72 6.21 5.79 5.60 5.42 5.11

Proved Undeveloped Reserves 6.24 5.85 5.51 5.36 5.22 4.96

Total Proved Reserves 6.68 6.18 5.76 5.58 5.40 5.09

Probable Reserves 8.65 6.56 5.16 4.63 4.17 3.46

Proved + Probable Reserves 7.96 6.43 5.37 4.96 4.60 4.03

Possible Reserves 7.94 5.53 4.03 3.49 3.05 2.38

Proved + Probable + Possible Reserves 7.95 5.90 4.58 4.10 3.69 3.06

(1) Company Gross reserves are based on Company working interest share of the reserves.

Company Net reserves are based on Company share of total Cost and Profit Revenues. Note, the government pays income taxes on behalf of the

Company out of the government's profit oil share. The net reserves were based on the effective pre-tax profit revenues by adjusting for the tax rate.

Genel Energy - Forecast Prices - Taq Taq Field - Dec 31 2015 - Final.xlsm 22/04/2016



Forecast of Production and RevenuesProved Producing Reserves

Forecast Price Case as of December 31, 2015

Property Gross Share of Production and Gross Revenues

Total Total Total

Producing Avg. Daily Annual Crude Sales

Well Rate Volume Oil Price Revenue

Year Count Bopd Mbbl US$/bbl US$MM

2016 22 70,000 25,550 42.33 1,081.5

2017 22 38,610 14,093 50.75 715.2

2018 19 20,705 7,557 59.43 449.2

2019 17 11,104 4,053 66.01 267.5

2020 16 5,955 2,174 69.99 152.1

2021 14 3,194 1,166 74.16 86.5

2022 11 1,603 585 78.77 46.1

2023 - - - - -

2024 - - - - -

2025 - - - - -

2026 - - - - -

2027 - - - - -

2028 - - - - -

2029 - - - - -

2030 - - - - -

Rem. - - - -

Total 55,177 2,798.1

Property Gross Share of Cost and Profit Revenues Contractor

Cost Cost Bal. Share of

State Total Oper. Oper. Total PSC Capital Aband. Net Recovery Cost at End Profit Profit

Royalties Royalties Costs Costs Bonuses Obligations Costs Costs Revenues Limit Revenues of Year Revenues Revenues

Year US$MM % US$MM US$/bbl US$MM US$MM US$MM US$MM US$MM US$MM US$MM US$MM US$MM frac

2016 108.1 10.0 63.4 2.48 - 0.6 29.8 2.5 877.1 389.3 96.3 - 877.1 0.251

2017 71.5 10.0 48.9 3.47 - 0.6 7.3 2.5 584.3 257.5 59.4 - 584.3 0.241

2018 44.9 10.0 36.7 4.86 - 0.6 - 2.6 364.3 161.7 39.9 - 364.3 0.235

2019 26.8 10.0 28.7 7.09 - 0.6 - 2.6 208.8 96.3 32.0 - 208.8 0.231

2020 15.2 10.0 24.6 11.31 - 0.6 - 2.7 109.0 54.8 27.9 - 109.0 0.230

2021 8.6 10.0 21.4 18.32 - 0.7 - 2.7 53.1 31.1 24.8 - 53.1 0.230

2022 4.6 10.0 18.3 31.23 - - - 2.8 20.4 16.6 16.6 4.5 24.9 0.230

2023 - - - - - - - - - - - 4.5 - 0.231

2024 - - - - - - - - - - - 4.5 - 0.231

2025 - - - - - - - - - - - 4.5 - 0.231

2026 - - - - - - - - - - - 4.5 - 0.231

2027 - - - - - - - - - - - 4.5 - 0.231

2028 - - - - - - - - - - - 4.5 - 0.231

2029 - - - - - - - - - - - 4.5 - 0.231

2030 - - - - - - - - - - - 4.5 - 0.231

Rem. - - - - - - - - - - - - -

Total 279.8 10.0 242.0 4.39 - 3.8 37.1 18.5 2,216.9 296.9 2,221.4

Company Share of Production and Revenues

Gross Net Capital & Bonuses

Ann. Oil Ann. Oil Cost Profit Oper. Aband. & Building PSC Addax Net NPV

Prod. Prod. Revenues Revenues Costs Costs Cap. Value Obligations Royalty Revenues 10.0%

Year Mbbl Mbbl US$MM US$MM US$MM US$MM US$MM US$MM US$MM US$MM US$MM

2016 11,242 3,920 53.0 96.9 34.9 17.7 29.1 0.3 - 67.8 64.6

2017 6,201 2,066 32.7 61.9 26.9 5.4 18.6 0.3 - 43.3 37.5

2018 3,325 1,108 22.0 37.6 20.2 1.4 11.3 0.3 - 26.3 20.7

2019 1,783 642 17.6 21.3 15.8 1.4 6.4 0.4 - 14.9 10.7

2020 956 403 15.4 11.0 13.5 1.5 3.3 0.4 - 7.7 5.0

2021 513 268 13.6 5.4 11.7 1.5 1.6 0.4 - 3.8 2.2

2022 257 153 9.1 2.5 10.1 1.5 0.8 - - (0.7) (0.4)

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Rem. - - - - - - - - - - -

Total 24,278 8,561 163.3 236.5 133.1 30.6 70.9 2.1 - 163.1 140.5




Forecast of Production and RevenuesTotal Proved Reserves



Total Total Total




2016 23 77,500 28,288 42.35 1,197.8

2017 24 41,961 15,316 50.78 777.7

2018 21 22,150 8,085 59.46 480.7

2019 19 11,693 4,268 66.03 281.8

2020 17 6,174 2,253 70.00 157.7

2021 15 3,260 1,190 74.17 88.3

2022 12 1,611 588 78.77 46.3

2023 - - - - -

2024 - - - - -

2025 - - - - -

2026 - - - - -

2027 - - - - -

2028 - - - - -

2029 - - - - -

2030 - - - - -

Rem. - - - -

Total 59,987 3,030.4






2016 119.8 10.0 66.9 2.36 - 0.6 46.3 2.5 961.8 431.2 116.2 - 961.8 0.251

2017 77.8 10.0 50.6 3.30 - 0.6 11.7 2.5 634.5 280.0 65.5 - 634.5 0.240

2018 48.1 10.0 37.6 4.65 - 0.6 - 2.6 391.9 173.1 40.8 - 391.9 0.234

2019 28.2 10.0 29.2 6.84 - 0.6 - 2.6 221.2 101.5 32.4 - 221.2 0.230

2020 15.8 10.0 24.9 11.03 - 0.6 - 2.7 113.8 56.8 28.2 - 113.8 0.229

2021 8.8 10.0 21.6 18.12 - 0.7 - 2.7 54.5 31.8 25.0 - 54.5 0.228

2022 4.6 10.0 18.4 31.35 - - - 2.8 20.5 16.7 16.7 4.6 25.0 0.229

2023 - - - - - - - - - - - 4.6 - 0.230

2024 - - - - - - - - - - - 4.6 - 0.230

2025 - - - - - - - - - - - 4.6 - 0.230

2026 - - - - - - - - - - - 4.6 - 0.230

2027 - - - - - - - - - - - 4.6 - 0.230

2028 - - - - - - - - - - - 4.6 - 0.230

2029 - - - - - - - - - - - 4.6 - 0.230

2030 - - - - - - - - - - - 4.6 - 0.230

Rem. - - - - - - - - - - - - -

Total 303.0 10.0 249.1 4.15 - 3.8 58.0 18.5 2,398.1 324.7 2,402.6






2016 12,447 4,436 63.9 106.2 36.8 26.8 31.9 0.3 - 74.3 70.9

2017 6,739 2,249 36.0 67.0 27.8 7.8 20.1 0.3 - 46.9 40.7

2018 3,557 1,168 22.4 40.3 20.7 1.4 12.1 0.3 - 28.2 22.2

2019 1,878 666 17.8 22.4 16.0 1.4 6.7 0.4 - 15.7 11.2

2020 991 412 15.5 11.4 13.7 1.5 3.4 0.4 - 8.0 5.2

2021 524 271 13.7 5.5 11.9 1.5 1.6 0.4 - 3.8 2.3

2022 259 154 9.2 2.5 10.1 1.5 0.8 - - (0.7) (0.4)

2023 - - - - - - - - - - -

2024 - - - - - - - - - - -

2025 - - - - - - - - - - -

2026 - - - - - - - - - - -

2027 - - - - - - - - - - -

2028 - - - - - - - - - - -

2029 - - - - - - - - - - -

2030 - - - - - - - - - - -

Rem. - - - - - - - - - - -

Total 26,394 9,356 178.6 255.4 137.0 42.0 76.6 2.1 - 176.3 152.1




Forecast of Production and RevenuesProved + Probable Reserves



Total Total Total




2016 24 80,000 29,200 42.28 1,234.4

2017 27 75,077 27,403 50.77 1,391.2

2018 29 65,771 24,006 59.54 1,429.2

2019 30 52,883 19,302 66.17 1,277.2

2020 30 42,123 15,375 70.19 1,079.2

2021 28 33,580 12,257 74.41 912.0

2022 26 26,788 9,777 78.62 768.7

2023 25 21,382 7,804 83.23 649.5

2024 24 17,075 6,232 84.83 528.7

2025 20 13,456 4,912 86.62 425.5

2026 19 10,777 3,934 88.31 347.3

2027 18 8,631 3,150 90.18 284.1

2028 17 6,912 2,523 91.96 232.0

2029 16 5,536 2,020 93.73 189.4

2030 16 4,433 1,618 95.70 154.9

Rem. - 2,334 98.48 229.8

Total 171,848 11,133.1






2016 123.4 10.0 68.1 2.33 - 0.6 49.6 - 992.7 444.4 118.3 - 992.7 0.251

2017 139.1 10.0 64.7 2.36 - 0.6 52.5 - 1,134.2 500.8 117.8 - 1,134.2 0.240

2018 142.9 10.0 59.7 2.49 - 0.6 51.0 - 1,174.9 514.5 111.4 - 1,174.9 0.229

2019 127.7 10.0 50.6 2.62 - 0.6 7.1 - 1,091.1 459.8 58.3 - 1,091.1 0.219

2020 107.9 10.0 46.8 3.04 - 0.6 - - 923.8 388.5 47.4 - 923.8 0.209

2021 91.2 10.0 43.7 3.56 - 0.7 - - 776.5 328.3 44.3 - 776.5 0.202

2022 76.9 10.0 41.2 4.21 - 0.7 - - 650.0 276.7 41.9 - 650.0 0.197

2023 65.0 10.0 39.3 5.03 - 0.7 - 3.0 541.6 233.8 43.0 - 541.6 0.193

2024 52.9 10.0 37.8 6.07 - 0.7 - 3.1 434.3 190.3 41.6 - 434.3 0.190

2025 42.5 10.0 36.3 7.39 - 0.7 - 3.1 342.8 153.2 40.1 - 342.8 0.189

2026 34.7 10.0 35.5 9.04 - 0.7 - 3.2 273.2 125.0 39.5 - 273.2 0.188

2027 28.4 10.0 35.0 11.12 - 0.7 - 3.2 216.7 102.3 39.0 - 216.7 0.188

2028 23.2 10.0 34.7 13.75 - 0.8 - 3.3 170.0 83.5 38.8 - 170.0 0.188

2029 18.9 10.0 34.5 17.09 - 0.8 - 3.4 131.8 68.2 38.7 - 131.8 0.188

2030 15.5 10.0 31.5 19.49 - 0.8 - 3.4 103.6 55.7 35.8 - 103.6 0.189

Rem. 23.0 10.0 54.0 23.15 - 0.8 - 7.1 144.9 61.9 - 144.9 0.191

Total 1,113.3 10.0 713.5 4.15 - 11.2 160.2 32.8 9,102.1 917.7 9,102.1






2016 12,848 4,564 65.0 109.6 37.4 27.3 32.9 0.3 - 76.7 73.2

2017 12,057 4,026 64.8 119.6 35.6 28.9 35.9 0.3 - 83.8 72.6

2018 10,563 3,347 61.3 118.3 32.9 28.1 35.5 0.3 - 82.8 65.2

2019 8,493 2,339 32.1 105.2 27.8 3.9 31.6 0.4 - 73.6 52.7

2020 6,765 1,787 26.1 85.2 25.7 - 25.5 0.4 - 59.6 38.8

2021 5,393 1,411 24.4 69.1 24.0 - 20.7 0.4 - 48.3 28.6

2022 4,302 1,128 23.0 56.3 22.7 - 16.9 0.4 - 39.4 21.2

2023 3,434 928 23.6 46.0 21.6 1.6 13.8 0.4 - 32.2 15.7

2024 2,742 769 22.9 36.4 20.8 1.7 10.9 0.4 - 25.4 11.3

2025 2,161 638 22.1 28.5 20.0 1.7 8.5 0.4 - 19.9 8.1

2026 1,731 544 21.7 22.6 19.6 1.7 6.8 0.4 - 15.8 5.8

2027 1,386 469 21.5 17.9 19.3 1.8 5.4 0.4 - 12.5 4.2

2028 1,110 410 21.3 14.1 19.1 1.8 4.2 0.4 - 9.8 3.0

2029 889 363 21.3 10.9 19.0 1.9 3.3 0.4 - 7.6 2.1

2030 712 311 19.7 8.6 17.3 1.9 2.6 0.4 - 6.0 1.5

Rem. 1,027 490 34.1 12.2 29.7 3.9 3.6 0.4 - 8.5 1.9

Total 75,613 23,524 504.7 860.2 392.4 106.2 258.1 6.2 - 602.1 406.0




Forecast of Production and RevenuesProved + Probable + Possible Reserves



Total Total Total




2016 24 82,000 29,930 42.28 1,265.5

2017 29 95,000 34,675 50.76 1,760.3

2018 35 105,000 38,325 59.53 2,281.5

2019 39 105,000 38,325 66.18 2,536.4

2020 39 105,000 38,325 70.22 2,691.1

2021 39 105,000 38,325 74.44 2,853.0

2022 37 105,000 38,325 78.66 3,014.6

2023 35 105,000 38,325 83.27 3,191.3

2024 33 80,382 29,339 84.85 2,489.5

2025 31 61,536 22,461 86.53 1,943.5

2026 29 47,109 17,195 88.20 1,516.7

2027 28 36,065 13,164 90.08 1,185.8

2028 26 27,610 10,078 91.85 925.6

2029 25 21,138 7,715 93.62 722.3

2030 21 15,938 5,817 95.70 556.7

Rem. - 16,052 101.61 1,631.0

Total 416,376 30,564.7






2016 126.5 10.0 68.9 2.30 - 0.6 49.6 - 1,019.8 455.6 119.1 - 1,019.8 0.251

2017 176.0 10.0 73.3 2.11 - 0.6 89.8 - 1,420.5 633.7 163.7 - 1,420.5 0.239

2018 228.2 10.0 79.8 2.08 - 0.6 92.9 - 1,880.2 821.4 173.2 - 1,880.2 0.227

2019 253.6 10.0 79.1 2.07 - 0.6 77.4 - 2,125.5 913.1 157.2 - 2,125.5 0.212

2020 269.1 10.0 80.8 2.11 - 0.6 4.7 - 2,335.8 968.8 86.2 - 2,335.8 0.198

2021 285.3 10.0 82.4 2.15 - 0.7 - - 2,484.7 1,027.1 83.1 - 2,484.7 0.182

2022 301.5 10.0 83.7 2.19 - 0.7 - - 2,628.7 1,085.3 84.4 - 2,628.7 0.167

2023 319.1 10.0 85.1 2.22 - 0.7 - - 2,786.3 1,148.9 85.8 - 2,786.3 0.156

2024 248.9 10.0 74.8 2.55 - 0.7 - - 2,165.0 896.2 75.5 - 2,165.0 0.156

2025 194.3 10.0 66.8 2.97 - 0.7 - - 1,681.6 699.7 67.5 - 1,681.6 0.156

2026 151.7 10.0 60.7 3.53 - 0.7 - - 1,303.6 546.0 61.4 - 1,303.6 0.156

2027 118.6 10.0 56.1 4.26 - 0.7 - - 1,010.4 426.9 56.8 - 1,010.4 0.156

2028 92.6 10.0 52.6 5.22 - 0.8 - 3.7 776.0 333.2 57.0 - 776.0 0.156

2029 72.2 10.0 50.0 6.48 - 0.8 - 3.8 595.5 260.0 54.5 - 595.5 0.156

2030 55.7 10.0 47.7 8.20 - 0.8 - 3.8 448.7 200.4 52.3 - 448.7 0.156

Rem. 163.1 10.0 292.6 18.23 - 5.1 - 29.0 1,141.1 324.8 - 1,143.0 0.156

Total 3,056.5 10.0 1,334.6 3.21 - 15.5 314.3 40.3 25,803.5 1,702.8 25,805.4






2016 13,169 4,657 65.5 112.6 37.9 27.3 33.8 0.3 - 78.8 75.2

2017 15,257 5,212 90.0 149.6 40.3 49.4 44.9 0.3 - 104.7 90.8

2018 16,863 5,274 95.3 187.5 43.9 51.1 56.2 0.3 - 131.2 103.4

2019 16,863 4,804 86.5 198.4 43.5 42.6 59.5 0.4 - 138.9 99.5

2020 16,863 4,059 47.4 203.7 44.5 2.6 61.1 0.4 - 142.6 92.9

2021 16,863 3,731 45.7 198.9 45.3 - 59.7 0.4 - 139.2 82.4

2022 16,863 3,459 46.4 193.4 46.1 - 58.0 0.4 - 135.4 72.9

2023 16,863 3,247 47.2 191.3 46.8 - 57.4 0.4 - 133.9 65.5

2024 12,909 2,533 41.5 148.6 41.1 - 44.6 0.4 - 104.0 46.3

2025 9,883 1,986 37.1 115.4 36.7 - 34.6 0.4 0.5 81.3 32.9

2026 7,566 1,567 33.8 89.5 33.4 - 26.8 0.4 2.5 65.2 24.0

2027 5,792 1,245 31.3 69.4 30.8 - 20.8 0.4 2.1 50.6 16.9

2028 4,434 1,018 31.4 53.3 28.9 2.0 16.0 0.4 1.7 39.0 11.9

2029 3,395 830 30.0 40.9 27.5 2.1 12.3 0.4 1.4 30.1 8.3

2030 2,560 676 28.8 30.8 26.2 2.1 9.2 0.4 1.2 22.8 5.7

Rem. 7,063 2,638 178.7 78.5 161.0 16.0 23.5 2.8 5.3 59.1 11.5

Total 183,205 46,935 936.5 2,061.6 734.0 195.0 618.5 8.5 14.7 1,456.7 839.8



Taq Taq Field - IraqCrude Oil Reserve Summary - Property Gross*

Effective December 31, 2015 June 2011 EvaluationTotal Total

Pilaspi Eocene Shiranish Kometan Qamchuqa Cretaceous TotalZone Matrix Fractures Zones Matrix Fractures Matrix Fractures Matrix Fractures Zones Field

Water Saturation, % 46.3 10.0 35.0 10.0 35.0 10.0 32.8 10.0 Oil Shrinkage, frac 0.98 0.98 0.93 0.93 0.93 0.93 0.93 0.93 Gross Rock Volume, E3 ac-ft 157 157 12,098 12,098 2,188 2,188 1,123 1,123 Area, acres 1,813 1,813 18,409 18,409 8,667 8,667 4,956 4,956 Net to Gross Ratio, frac 0.51 1.00 0.026 1.00 0.103 1.00 0.240 1.00 Avg Net Pay, ft 44.5 86.6 17.0 657.2 26.0 252.4 54.4 226.5

Proved Producing Reserves (PDP)1P Porosity, % 16.2 0.30 - 0.21 7.0 0.57 10.0 0.57 1P Original Oil in Place, Mbbl 53,373 3,223 56,596 - 160,333 73,128 80,282 130,078 41,200 485,022 541,618 Recovery Factor, % 2.5 70.0 6.3 - 77.0 2.5 80.0 10.0 80.0 48.6 44.1 Original Recoverable, Mbbl 1,334 2,256 3,590 - 123,457 1,828 64,226 13,008 32,960 235,479 239,069 Cumulative Production, Mbbl - 1,170 1,170 - 70,700 1,828 64,226 13,008 32,960 182,722 183,892 Cumulative Recovery, % - 36.3 2.1 - 44.1 2.5 80.0 10.0 80.0 37.7 34.0 Remaining Recoverable, Mbbl 1,334 1,086 2,421 - 52,757 - - - - 52,757 55,177

Total Proved Reserves (1P)Recovery Factor, % 2.5 70.0 6.3 - 80.0 2.5 80.0 10.0 80.0 49.5 45.0 Original Recoverable, Mbbl 1,334 2,256 3,590 - 128,267 1,828 64,226 13,008 32,960 240,289 243,879 Cumulative Production, Mbbl - 1,170 1,170 - 70,700 1,828 64,226 13,008 32,960 182,722 183,892 Remaining Recoverable, Mbbl 1,334 1,086 2,421 - 57,567 - - - - 57,567 59,987

Proved + Probable Reserves (2P)2P Porosity, % 16.2 0.50 - 0.38 7.0 0.57 10.0 0.57 2P Original Oil in Place, Mbbl 53,373 5,371 58,744 - 296,276 73,128 80,282 130,078 41,200 620,964 679,709 Recovery Factor, % 5.0 75.0 11.4 - 80.0 2.5 80.0 10.0 80.0 56.2 52.3 Original Recoverable, Mbbl 2,669 4,028 6,697 - 237,021 1,828 64,226 13,008 32,960 349,043 355,740 Cumulative Production, Mbbl - 1,170 1,170 - 70,700 1,828 64,226 13,008 32,960 182,722 183,892 Remaining Recoverable, Mbbl 2,669 2,859 5,528 - 166,321 - - - - 166,321 171,848

Proved + Probable + Possible Reserves (3P)3P Porosity, % 16.2 0.70 8.4 0.70 7.0 0.57 10.0 0.57 3P Original Oil in Place, Mbbl 53,373 7,520 60,893 122,844 547,480 73,128 80,282 130,078 41,200 995,012 1,055,905 Recovery Factor, % 10.0 80.0 18.6 3.5 85.0 3.5 80.0 15.0 80.0 59.2 56.8 Original Recoverable, Mbbl 5,337 6,016 11,353 4,300 465,358 2,559 64,226 19,512 32,960 588,915 600,268 Cumulative Production, Mbbl - 1,170 1,170 - 70,700 1,828 64,226 13,008 32,960 182,722 183,892 Remaining Recoverable, Mbbl 5,337 4,846 10,184 4,300 394,658 731 - 6,504 - 406,193 416,376

* These are property gross technical reserves before application of an economic limit and without accounting for license expiry.The 2P and 3P Recovery Factors in the Total Eocene Zones column were incorrectly stated in the original version of this document. The figures in this table show the correct Recovery Factors. The 2P and 3P Original Oil in Place and Remaining Recoverable estimates for the Total Eocene Zones are unchanged from the original version of this document

Genel Energy - Forecast Prices - Taq Taq Field - Dec 31 2015 - Final v2.xlsm 27/04/2016



Reservoir and Fluid Properties

Effective December 31, 2015

Pilaspi Shiranish Kometan Quamchuqa

Zone Zone Zone Zone

Imperial Units

Lithology Dolomite Limestone Limestone Dolomite

Maximum Gross Pay Thickness (over total field), ft 180 955 390 577

Average Depth to Reservoir, ft 1,804 5,741 6,234 6,562

Oil Water Contact Depth, ft SS (148) 4,954 4,954 4,954

Initial Reservoir Pressure (at O/W Contact), atm 51 197 197 197

Initial Reservoir Pressure (at O/W Contact), psia 750 2,900 2,900 2,900

Bubble Point Pressure, atm 21.8 11.2 10.9 11.8

Bubble Point Pressure, psia 320 165 160 173

Reservoir Temperature, F 113 160 160 160

Stock Tank Oil Density, g/cc 0.900 0.786 0.786 0.786

Stock Tank Oil Gravity, degrees API 25.7 48.5 48.5 48.5

Oil Viscosity at Reservoir Pressure, cp 16 0.72 0.72 0.72

Solution GOR, scf/bbl 50 30 26 32

Pilaspi Shiranish Kometan Quamchuqa

Zone Zone Zone Zone

Metric Units

Lithology Dolomite Limestone Limestone Dolomite

Maximum Gross Oil Pay Thickness (over total field), m 55 291 119 176

Average Depth to Reservoir, m 550 1,750 1,900 2,000

Oil Water Contact Depth, m SS (45) 1,510 1,510 1,510

Initial Reservoir Pressure (at O/W Contact), atm 51 197 197 197

Initial Reservoir Pressure (at O/W Contact), Kpa 5,168 19,984 19,984 19,984

Bubble Point Pressure, atm 21.8 11.2 10.9 11.8

Bubble Point Pressure, kpa 2,205 1,137 1,103 1,192

Reservoir Temperature, C 45 71 71 71

Stock Tank Oil Density, g/cc 0.900 0.786 0.786 0.786

Stock Tank Oil Gravity, degrees API 25.7 48.5 48.5 48.5

Oil Viscosity at Reservoir Pressure, cp 16 0.72 0.72 0.72

Solution GOR, m3/m3 9 5 5 6




Summary of Economic Parameters


Price Schedule

McDaniel & Associates January 1, 2016 Forecast Price Case

See Table 14

Operating Costs (2016$ - US)

Description PDP Case 1P Case 2P Case 3P Case

G&A + Fixed, $M/yr

2016 $29,640 $29,640 $29,640 $29,640

2017 $29,640 $29,640 $29,640 $29,640

2018 $24,530 $24,530 $27,085 $29,640

After 2018 $20,442 $20,442 $22,486 $27,085

Variable, $/w-m $9,900 $9,900 $9,900 $9,900

Variable, $/bbl

2016 $1.22 $1.22 $1.22 $1.22

After 2016 $1.12 $1.12 $1.12 $1.12

* G&A + Fixed costs were reduced by 10 percent per year in each of the last three years of the forecast

Capital Costs (2016$ - US)

See Table 13

Abandonment Costs (2016$ - US)

Abandonments $13,900,000 plus $420,000 / well

- Allocated to each of the last 10 years of each forecast

* Abandonments include both well and surface facility expenses as estimated by Genel

Interests and Fiscal Terms (2016$ - US)

Genel Working Interest for Costs 55 percent

Genel Working Interest for Revenues 44 percent

State Royalty 10 percent

Production Bonus - Based on cumulative export production

Start of Production $2.5 million

0 to 25,000 bbl $5.0 million

25,000 to 50,000 bbl $10.0 million

50,000+ $20.0 million

Cost Recovery Limit 40 percent of sales revenue less royalties

Total Cost Recovery Balance at December 31, 2015 $0

Genel Cost Recovery Balance at December 31, 2015 $0

Cumulative Costs at December 31, 2015 $1,496 million

Cumulative Revenue at December 31, 2015 $2,260 million

Contractor Share of Profit Oil Based on R-Factor = Cumulative Revenues / Cumulative Costs

R < 1.0 30 percent

1 < R < 2.5 30% - (30-15.6)*(R-1)/(2.5-1)

R > 2.5 15.625 percent

Capacity Building Value Bonus 30 percent of Genel's profit oil

PSC Obligations (Training and Environmental) $0.6 million

Income Tax Not applicable (40 % tax is paid out of government profit oil share)

Contract expiry February 26, 2033

(Contract extension assumed in 3P Case)

Addax Royalty 2.5 percent of the Addax cost oil and profit oil.

The consideration will revert to Genel after the Addax Royalty Balance is repaid.

Addax Royalty Balance at December 31, 2015 $46 million paid out of the 2.5 percent of gross revenue

Interest Rate on Deferred Balance 1.5 percent



Taq Taq Field - Iraq Page 1

Forecast of Capital Costs - 2016$Effective December 31, 2015

Proved Producing Reserves

Production Wells ESP and PCP Pumps Water Disposal Wells Infrastruct. Studies Total Total

Cret. Cret. Pilaspi ESP PCP & Facilities Costs Area Area

Year STK# HZ# # 2016 US$M # # 2016 US$M # 2016 US$M 2016 US$M 2016 US$M 2016 US$M Future US$M

2016 - - - - 3 - 7,200 1 500 14,150 7,920 29,770 29,770

2017 - - - - 3 - 7,200 - - - - 7,200 7,344

2018 - - - - - - - - - - - - -

2019 - - - - - - - - - - - - -

2020 - - - - - - - - - - - - -

2021 - - - - - - - - - - - - -

2022 - - - - - - - - - - - - -

2023 - - - - - - - - - - - - -

2024 - - - - - - - - - - - - -

2025 - - - - - - - - - - - - -

2026 - - - - - - - - - - - - -

2027 - - - - - - - - - - - - -

2028 - - - - - - - - - - - - -

2029 - - - - - - - - - - - - -

2030 - - - - - - - - - - - - -

2031 - - - - - - - - - - - - -

Total - - - - 6 - 14,400 1 500 14,150 7,920 36,970 37,114

Individual Cost $M

5,500 17,450 3,050 2,400 300 500

Total Proved Reserves




2016 2 - - 11,000 5 - 12,000 1 500 14,150 8,600 46,250 46,250

2017 - - - - 3 - 7,200 - - - 4,300 11,500 11,730

2018 - - - - - - - - - - - - -

2019 - - - - - - - - - - - - -

2020 - - - - - - - - - - - - -

2021 - - - - - - - - - - - - -

2022 - - - - - - - - - - - - -

2023 - - - - - - - - - - - - -

2024 - - - - - - - - - - - - -

2025 - - - - - - - - - - - - -

2026 - - - - - - - - - - - - -

2027 - - - - - - - - - - - - -

2028 - - - - - - - - - - - - -

2029 - - - - - - - - - - - - -

2030 - - - - - - - - - - - - -

2031 - - - - - - - - - - - - -

Total 2 - - 11,000 8 19,200 1 500 14,150 12,900 57,750 57,980

Individual Cost $M

5,500 17,450 3,050 2,400 300 500



Taq Taq Field - Iraq Page 2

Forecast of Capital Costs - 2016$Effective December 31, 2015

Total Proved + Probable Reserves




2016 2 - 1 14,050 5 1 12,300 1 500 14,150 8,600 49,600 49,600

2017 2 1 - 28,450 6 - 14,400 - - - 8,600 51,450 52,479

2018 2 1 - 28,450 5 - 12,000 - - - 8,600 49,050 51,032

2019 - - - - 1 - 2,400 - - - 4,300 6,700 7,110

2020 - - - - - - - - - - - - -

2021 - - - - - - - - - - - - -

2022 - - - - - - - - - - - - -

2023 - - - - - - - - - - - - -

2024 - - - - - - - - - - - - -

2025 - - - - - - - - - - - - -

2026 - - - - - - - - - - - - -

2027 - - - - - - - - - - - - -

2028 - - - - - - - - - - - - -

2029 - - - - - - - - - - - - -

2030 - - - - - - - - - - - - -

2031 - - - - - - - - - - - - -

Total 6 2 1 70,950 17 41,100 1 500 14,150 30,100 156,800 160,221

Individual Cost $M

5,500 17,450 3,050 2,400 300 500

Total Proved + Probable + Possible Reserves




2016 2 - 1 14,050 5 1 12,300 1 500 14,150 8,600 49,600 49,600

2017 4 2 1 59,950 8 1 19,500 - - - 8,600 88,050 89,811

2018 2 3 - 63,350 7 - 16,800 1 500 - 8,600 89,250 92,856

2019 - 3 - 52,350 5 - 12,000 - - - 8,600 72,950 77,415

2020 - - - - - - - - - - 4,300 4,300 4,654

2021 - - - - - - - - - - - - -

2022 - - - - - - - - - - - - -

2023 - - - - - - - - - - - - -

2024 - - - - - - - - - - - - -

2025 - - - - - - - - - - - - -

2026 - - - - - - - - - - - - -

2027 - - - - - - - - - - - - -

2028 - - - - - - - - - - - - -

2029 - - - - - - - - - - - - -

2030 - - - - - - - - - - - - -

2031 - - - - - - - - - - - - -

Total 8 8 2 189,700 25 60,600 2 1,000 14,150 38,700 304,150 314,336

Individual Cost $M

5,500 17,450 3,050 2,400 300 500


McDaniel & Associates Consultants Ltd. Table 14

Summary of Price Forecasts


Taq Taq Taq Taq Taq Taq Taq Taq Taq Taq

Brent Cretaceous Pilaspi Transport Cretaceous Pilaspi

Crude Quality Quality & Handling Sales Sales Inflation

Oil Price Differential Differential Differential Oil Price Oil Price Forecast

Year $US/bbl $US/bbl $US/bbl $US/bbl $US/bbl $US/bbl %

2016 47.50 1.00 7.00 4.00 42.50 36.50 2.00

2017 56.20 1.02 7.14 4.08 51.10 44.98 2.00

2018 65.00 1.04 7.28 4.16 59.80 53.56 2.00

2019 71.70 1.06 7.43 4.24 66.39 60.03 2.00

2020 75.80 1.08 7.58 4.33 70.39 63.89 2.00

2021 80.10 1.10 7.73 4.42 74.58 67.96 2.00

2022 84.40 1.13 7.88 4.50 78.77 72.01 2.00

2023 89.10 1.15 8.04 4.59 83.36 76.46 2.00

2024 90.80 1.17 8.20 4.69 84.94 77.91 2.00

2025 92.60 1.20 8.37 4.78 86.62 79.45 2.00

2026 94.40 1.22 8.53 4.88 88.31 80.99 2.00

2027 96.40 1.24 8.70 4.97 90.18 82.72 2.00

2028 98.30 1.27 8.88 5.07 91.96 84.35 2.00

2029 100.20 1.29 9.06 5.17 93.73 85.97 2.00

2030 102.30 1.32 9.24 5.28 95.70 87.79 2.00

2031 104.35 1.35 9.42 5.38 97.62 89.54 2.00

2032 106.43 1.37 9.61 5.49 99.57 91.33 2.00

2033 108.56 1.40 9.80 5.60 101.56 93.16 2.00

2034 110.73 1.43 10.00 5.71 103.59 95.02 2.00

2035 112.95 1.46 10.20 5.83 105.66 96.92 2.00

Pricing Assumptions :

Brent price forecast based on the McDaniel & Associates January 1, 2016 price forecast

Total 2016 differential for 48.5 API, Cretaceous oil is $5/bbl made up of 1$/bbl for quality and 4$/bbl from transport & handling costs.

Total 2016 differential for 25.7 API, Pilaspi oil is $11/bbl made up of 7$/bbl for quality and 4$/bbl from transport & handling costs.


TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25TT-26

TT-27

TT-28

Initial Estimated OWC +45 m ASL

9297

-72

93

92

-8

17

19

-39

75 87

24

92

-68

65

-10

52

65

-141

-38

-42

9494

8474

9190

73

-103

3984000 3984000

3987000 3987000

453000

453000

456000

456000

459000

459000

Genel Energy International Ltd. Taq Taq Field - Iraq Top Structure Map Pilaspi Reservoir

<AT> Units – meters 18 December, 2015

Well Legend Map Abbreviations

Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 km

Figure 5

CI=20m

TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25TT-26

TT-27

TT-28

Initial Estimated OWC +45 m ASL3984000 3984000

3987000 3987000

453000

453000

456000

456000

459000

459000

Genel Energy International Ltd. Taq Taq Field - Iraq

Gross Oil Thickness Map Pilaspi Reservoir



Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 km

CI=10m

Figure 6

Initial Estimated OWC -1510 m SS

-981

-1152

-981

-1013

-1064

-1078

-1034

-1112

-977

-1015

-970

-1085

-1030

-1092

-990

-1019

-1153

-1099

-1131

-1025-1027

-1034

-980

-1000

-1128

TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25 TT-26

TT-27

TT-28

3978000 3978000

3981000 3981000

3984000 3984000

3987000 3987000

3990000 3990000

3993000 3993000

450000

450000

453000

453000

456000

456000

459000

459000

462000

462000

Genel Energy International Ltd. Taq Taq Field - Iraq Top Structure Map Shiranish Reservoir



Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 3 km

Figure 7

CI=50m


TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25 TT-26

TT-27

TT-28

3978000 3978000

3981000 3981000

3984000 3984000

3987000 3987000

3990000 3990000

3993000 3993000

450000

450000

453000

453000

456000

456000

459000

459000

462000

462000


Gross Oil Thickness Map Shiranish Reservoir

<AT> Units – meters 16 March, 2016


Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 3 km

Figure 8

CI=50m


-1216

-1230

-1275

-1362

-1319

-1303

-1381

-1202

-1242

-1210

-1349

-1295

-1362

-1232

-1283

-1400

-1390

-1365

-1411

-1322

-1252

-1393

TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25 TT-26

TT-27

TT-28

3978000 3978000

3981000 3981000

3984000 3984000

3987000 3987000

3990000 3990000

3993000 3993000

450000

450000

453000

453000

456000

456000

459000

459000

462000

462000

Genel Energy International Ltd. Taq Taq Field - Iraq Top Structure Map Kometan Reservoir



Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 3 km

Figure 9

CI=50m


TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25 TT-26

TT-27

TT-28

3978000 3978000

3981000 3981000

3984000 3984000

3987000 3987000

3990000 3990000

3993000 3993000

450000

450000

453000

453000

456000

456000

459000

459000

462000

462000


Gross Oil Thickness Map Kometan Reservoir



Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 3 km

Figure 10

CI=50m


-1315

-1331

-1350

-1476

-1430

-1374

-1485

-1298

-1339

-1307

-1435

-1409

-1435

-1329

-1376

-1494

-1514

-1467

-1553

-1404

-1350

-1495

TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25 TT-26

TT-27

TT-28

3978000 3978000

3981000 3981000

3984000 3984000

3987000 3987000

3990000 3990000

3993000 3993000

450000

450000

453000

453000

456000

456000

459000

459000

462000

462000

Genel Energy International Ltd. Taq Taq Field - Iraq Top Structure Map

Qamchuqa Reservoir



Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 3 km

Figure 11

CI=50m


TT-01TT-02

TT-03

TT-04

TT-05

TT-06

TT-07

TT-08

TT-09

TT-10Z TT-11

TT-12

TT-13

TT-14

TT-15

TT-16

TT-17

TT-18

TT-19Z

TT-20

TT-21

TT-22WTT-22X

TT-23

TT-24

TT-25 TT-26

TT-27

TT-28

3978000 3978000

3981000 3981000

3984000 3984000

3987000 3987000

3990000 3990000

3993000 3993000

450000

450000

453000

453000

456000

456000

459000

459000

462000

462000


Gross Oil Thickness Map Qamchuqa Reservoir



Oil producer

Oil well

Gas producer

Gas well

Status unknown

Abandoned

Water injector

Drilling location

OWC

GOC

GWC

NT

NP

NDE

LTG

LTO

LKO

-

-

-

-

-

-

-

-

-

Oil Water Contact

Gas Oil Contact

Gas Water Contact

Not Tested

Not Present

Not Deep Enough

Lowest Tested Gas

Lowest Tested Oil

Lowest Known Oil

1 0 1 2 3 km

Figure 12

CI=50m

Figure 13

Genel Energy - Forecast Prices - Taq Taq Field - Dec 31 2015 - prelim - Mar 22 PT.xlsm 28/03/2016

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034 2036 2038

Pro

du

cti

on

Ra

te -

Bo

pd

Year

Taq Taq Field - IraqTotal Field Production Forecast

100 Percent Working Interest Before Royalty

History PDP 1P 2P 3P

Documents

GENEL ENERGY INTERNATIONAL LTD. · Reference: Genel Energy International Ltd. Competent Person’s Report as of December 31, 2015 Taq Taq Field Attention: Prof. Fevzi Gumrah, Subsurface