RPS March 2 2014 Reserves FINAL

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Mnazi Bay Field

Reserves Assessmentas at December 31, 2014



Suite 700, 555 – 4th Avenue S.W., Calgary, Alberta T2P 3E7 CanadaT +1 403 265 7226 F +1 403 269 3175 E [email protected] www rpsgroup.com/canada

March 2, 2015

Job No. ECV 14-3492/CC01048

Wentworth Resources Li mited3210, 715 – 5th Avenue SWCalgary, Alberta Canada T2P 2X6

At ten tion : Mr. Geof frey Bu ry , Managi ng Dir ect or

Dear Mr. Bury,

Re: Mnazi Bay Reserves Assessment , as at December 31, 2014



The Mnazi Bay Licence also contains additional hydrocarbon potential in a number of undrilledlocations, however evaluation of these prospects is outside of the scope of this engagement.

This report is issued by RPS under the appointment by Maurel et Prom and is produced as partof the engagement detailed therein and subject to the terms and conditions of the Agreement.Those terms and conditions contain inter alia restrictions on the use and distribution ofinformation and materials contained in this report.

This report is addressed to Wentworth, a named Third Party as defined in the Agreement and isonly capable of being relied on by Wentworth and the Third Parties under and pursuant to (and

bj h f) h A

Reserves Summary for Mnazi Bayas at December 31, 2014

Field Wentworth 31.94% WI

Reserves Sales Gas BOE Sales Gas BOE Sales Gas BOECategory (Bscf) (MMbbl) (Bscf) (MMbbl) (Bscf) (MMbbl)

PDP 82.9 13.8 26.5 4.4 20.7 3.5

1P 279.2 46.5 89.2 14.9 68.2 11.42P 443.0 73.8 141.5 23.6 95.5 15.93P 709.3 118.2 226.6 37.8 135.3 22.6

(1) Gross Reserves are Company Working Interest Share of Total Field Reserves(2) Net Reserves are calculated as the product of Company Gross Reserves and the ratio of Company net revenue to Company WI share of field gross revenue

Gross (1) Reserves Gross (1) Reserves Net (2) Reserves



RPS Mnazi Bay Reserves Assessment, as at December 31, 2014

EXECUTIVE SUMMARY

RPS has reviewed the available data for the Mnazi Bay Concession Area in South-East Tanzaniaand has evaluated Wentworth Resources’ 31.94% (production operations) working interest in thereserves volumes of the 756 km 2 area. The effective date of this report is December 31, 2014.







The NPV estimates associated with these reserves volumes, by Company are:

Wentworth Resources Working Interest Reserves for Mnazi Bayas at December 31, 2014

RPS Forecast 2015-01-01

Reserve Category Oil Sales Gas NGL& C5 + BOE Oil Sales Gas NGL& C5 + BOE(MMstb) (Bscf) (MMbbl) (MMbbl) (MMstb) (Bscf) (MMbbl) (MMbbl)

PROVEDProducing - 26.5 - 4.4 - 20.7 - 3.5

Non Producing Undeveloped - 62.7 - 10.5 - 47.4 - 7.9Total Proved - 89.2 - 14.9 - 68.2 - 11.4

Probable - 52.3 - 8.7 - 27.3 - 4.5

PROVED + PROBABLE - 141.5 - 23.6 - 95.5 - 15.9Possible - 85.1 - 14.2 - 39.9 - 6.6

PROVED + PROBABLE + POSSIBLE - 226.6 - 37.8 - 135.3 - 22.6

Gross Reserves Net Reserves

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RESERVE DEFINITIONS

The following definitions have been used by RPS Energy Canada Ltd. (RPS) in evaluatingreserves. These definitions meet the requirements of the Canadian National Instrument 51-101,“Standards of Disclosure for Oil and Gas Activities” and its companion policy. These definitionsare based on the following references:

1. Society of Petroleum Evaluation Engineers (Calgary Chapter) and Canadian Institute ofMining, Metallurgy & Petroleum (Petroleum Society) - “Canadian Oil and Gas EvaluationHandbook, Volume 1, Second Edition”, September 1, 2007.

2. Society of Petroleum Evaluation Engineers (Calgary Chapter) and Canadian Institutionof Mining, Metallurgy and Petroleum - “Canadian Oil and Gas Evaluation Handbook,Volume 2, First Edition”, November 1, 2005.

3. Society of Petroleum Engineers, World Petroleum Council, American Association ofPetroleum Geologists and Society of Petroleum Evaluation Engineers - “Petroleum

Resource Management System (SPE – PRMS)”, 2007.ReservesReserves are volumes of hydrocarbons and associated substances estimated to be commerciallyrecoverable from known accumulations from a given date forward by established technologyunder specified economic conditions and government regulations. Specified economic conditionsmay be current economic conditions in the case of constant price and uninflated cost forecasts(as required by many financial regulatory authorities) or they may be reasonably anticipatedeconomic conditions in the case of escalated price and inflated cost forecasts.




Proved Developed Producing Reserves (PDP) Proved developed producing reserves are those reserves expected to be recovered fromcompletion intervals open at the time of estimate. They may be actually on production or, iftemporarily shut in, the date of resumption of production known with a reasonable certainty.

Proved Developed Non-Producing Reserves (PDNP) Proved developed non-producing reserves include shut in and behind pipe reserves. Shut inreserves are expected to be recovered from existing completions that are shut in for marketingconstraints or require minor capital expenditures (such as tie ins) and the date of production isuncertain. Behind pipe reserves are expected to be recovered from zones behind casing inexisting wells and require minor capital expenditures (such as perforating) for completion prior toproduction at a date that is uncertain.

Proved Undeveloped Reserves (PUD)Proved undeveloped reserves are those reserves expected to be recovered from knownaccumulations where a significant capital expenditure (compared to the cost of drilling a well) isrequired to render them capable of production. These reserves may be assigned to new wells,major recompletions or major facility expenditures.

Probable Reserves (PROB)Probable reserves (also called Probable Additional reserves) are quantities of recoverablehydrocarbons estimated on the basis of engineering and geological data that are similar to thoseused for proved reserves but that lack, for various reasons, the certainty required to classify thereserves are proved. Probable reserves are less certain to be recovered than proved reserves;which means, for purposes of reserves classification, that there is 50% probability that more than

h P d l P b bl Addi i l ill ll b d Th i l d




TABLE OF CONTENTS

LETTER OF TRANSMITTAL

EXECUTIVE SUMMARY IV

CERTIFICATE OF QUALIFICATION B.D. WEATHERILL XV

INDEPENDENT PETROLEUM CONSULTANT'S CONSENT AND WAIVER OF LIABILITY XVI

1.0 INTRODUCTION 1-1

1.1 Background and Historical Description 1-1

1.2 Scope 1-4

1.3 Data Sources 1-4

1.4 Prior Assessments 1-4

1.5 Reserve Definitions 1-5

2.0 CONCESSION AREAS 2-1

2.1 Mnazi Bay Licence, Tanzania 2-1

2.1.1 Interests and Burdens 2-2

2.1.2 Mnazi Bay Licence Block Exploration History 2-3

3.0 REGIONAL GEOLOGY AND PETROLEUM SYSTEM 3-1

3.1 Regional Geological Setting 3-1

3.2 Tertiary Depositional Environments 3-3

3.3 Tertiary Stratigraphy 3-4




TABLE OF CONTENTS

4.5 Mnazi Bay Volumes and Reserves 4-19

4.5.1 Reserves Determination Methodology 4-20

4.5.2 Gross Rock Volume 4-20

4.5.3 Initial Hydrocarbons in Place (GIIP) 4-21

4.5.4 Technically Recoverable Reserves 4-22

4.5.5 Production Forecasting 4-23

5.0 ECONOMICS AND RESERVES 5-1

5.1 PSA and Development Licence 5-1

5.2 Company Ownership and Working Interest 5-2

5.3 Product Price 5-3

5.4 Capex 5-5

5.5 Opex 5-6

5.5.1 Abandonment Costs 5-6

5.6 Fuel Gas 5-6

5.7 Taxation 5-7

5.8 Existing Cost, Tax and TPDC Carry Pools 5-7

5.9 Reserves and Economic Results 5-8

6.0 REFERENCES 6-1




TABLE OF CONTENTS

LIST OF TABLES

Table 1-1: Summary Table of Assets 1-2

Table 4-1: Log Evaluation Summary 4-8

Table 4-2: Gas-Water Contact Data 4-12

Table 4-3: Selected Gas-Water Contact 4-13

Table 4-4: MB-2 Gas Composition 4-14 Table 4-5: MB-03 Gas Composition 4-15

Table 4-6: Extended Well Testing Fluid Production Summary 4-15

Table 4-7: Mnazi Bay & Msimbati Fields Well Test Summary 4-17

Table 4-8: Mnazi Bay and Msimbati DST Summary 4-17

Table 4-9: Hydrocarbon-bearing Gross Rock Volumes 4-20

Table 4-10: Input Parameters and Distributions 4-21

Table 4-11: Mnazi Bay GIIP Volumes (Bscf) 4-22

Table 4-12: EWT Material Balance Estimates 4-22

Table 4-13: EUR and Recovery Factor Summary 4-28

Table 5-1: Mnazi Bay Development Licence Company Interests 5-2

Table 5-2: Mnazi Bay Exploration Licence Company Interests 5-3




TABLE OF CONTENTS

LIST OF FIGURES

Figure 1-1: Location Map of Mnazi Bay Licence 1-1

Figure 1-2: Mnazi Bay Licence Area 1-3

Figure 2-1: Mnazi Bay Concession, Tanzania 2-1

Figure 2-2: Mnazi Bay showing Mnazi Bay/Msimbati Field 2-2

Figure 3-1: Location Map Ruvuma Basin 3-1 Figure 3-2: Stratigraphic Chart 3-2

Figure 3-3: Tanzania Tertiary Deposition - Canyon Slope Setting 3-3

Figure 3-4: Mozambique Tertiary Deposition. Onshore Block: Fluvial-Deltaic and MarineShelf Sandstone. 3-3

Figure 3-5: Cross Section across On-Shore Tanzania and Mozambique Showing Upper andLower Tertiary Environments and Reservoir/Seal Pairs 3-4

Figure 3-6: Evolution of the Ruvuma Basin with Stratigraphic Units 3-5

Figure 3-7: Cross Section Showing the Linked Extensional and Basinward Toe ThrustSystem 3-6

Figure 4-1: Mnazi Bay Stratigraphic Section 4-2

Figure 4-2: Msimbati Field MS-1X K Sands – Stratigraphic Section 4-3

Figure 4-3: Pre-Tertiary Unconformity Surface (Top Upper Cretaceous) 4-4




TABLE OF CONTENTS

Figure 4-20: Mnazi Bay GAP model example (with 5 wells) 4-25

Figure 4-21: Development Plan Zonal Modelling Schematic for Reserves Cases 4-26

Figure 4-22: Mnazi Bay Field Gas Production Forecast 4-27

Figure 4-23: Mnazi Bay Field Cumulative Gas Production Forecast 4-28

Figure 5-1: Mnazi Bay Gas Price with 2P Blended Price 5-5

Figure 5-2: Total Opex estimates 5-6

LIST OF APPENDICES

Appendix 1 Glossary of Technical Terms

Appendix 2 Mnazi Bay/Msimbati Structure and Isopach Maps




LEGAL NOTICE

This report is issued by RPS under the appointment by Maurel et Prom in the engagement letterdated November 28, 2014 (the “Agreement”), and is produced as part of the engagementdetailed therein and subject to the terms and conditions of the Agreement.

This report is addressed to Wentworth Resources Limited, a named Third Party as defined inthe Agreement and is only capable of being relied on by Maurel et Prom and the Third Partiesunder and pursuant to (and subject to the terms of) the Agreement.

Maurel et Prom may disclose the signed and dated report to third parties as contemplated bythe purpose detailed in the Agreement but in making any such disclosure Maurel et Prom shallrequire the third party (including any Third Parties) to accept it as confidential information only tobe used or passed on to other persons as Maurel et Prom is permitted to do under the

Agreement.

This document was prepared by RPS Energy Canada Ltd. (operating as RPS) solely for thebenefit of Maurel et Prom and the Third Parties (including Wentworth) named in the Agreement.

Neither RPS Energy, their parent corporations or affiliates, nor any person acting in their behalf:

makes any warranty, expressed or implied, with respect to the use of any information ormethods disclosed in this document; or

assumes any liability with respect to the use of any information or methods disclosed in




CERTIFICATE OF QUALIFICATIONB.D. Weatheril l

I, Brian D. Weatherill, a Professional Engineer at RPS Energy Canada Ltd., and co-author of a

property evaluation (the "Evaluation") dated March 2, 2015 prepared for Wentworth Resources

Limited, do hereby certify that:

• I am a Petroleum Engineer employed by RPS Energy Canada Ltd., which prepared aResource Assessment of the Mnazi Bay, Tanzania assets, the Rovuma Onshore Blockin Mozambique and an opinion as to the potential of the Mozambique Rovuma Offshore

Area 1 Block assets of Wentworth Resources Limited, as of December 31, 2014.• I attended the University of British Columbia and that I graduated with a Bachelor of

Applied Science Degree Geological Engineering in 1973; that I am a registered

Professional Engineer in the Province of Alberta (APEGGA); and that I have in excess of35 years’ experience in Petroleum Engineering relating to Canadian and international oiland gas properties.

• I and my employer are independent of Wentworth and our remuneration is not related inany way to Wentworth’s value or any Wentworth financing or capital funding activities.

• I have not, directly or indirectly, received an interest, and I do not expect to receive aninterest, direct or indirect, in Wentworth Resources Limited or any associate or affiliate ofthat company.




INDEPENDENT PETROLEUMCONSULTANT'S CONSENT

AND WAIVER OF LIABILITY

The undersigned firm of Independent Petroleum Consultants of Calgary, Alberta, Canada knowsthat it is named as having prepared an independent report of the gas reserves of the Tanzanian

property owned by Maurel et Prom and Wentworth Resources and it hereby gives consent to theuse of its name and to the said report. The effective date of the report is December 31, 2014.

In the course of the assessment, Maurel et Prom and Wentworth Resources provided RPSEnergy personnel with basic information which included petroleum and licensing agreements,geologic, geophysical and production information, cost estimates, contractual terms and studiesmade by other parties. Any other engineering or economic data required to conduct the

assessment upon which the original and addendum reports are based, was obtained from publicliterature, and from RPS Energy non-confidential client files and previous technical resourceassessment reports on the subject property. The extent and character of ownership andaccuracy of all factual data supplied for this assessment, from all sources, has been accepted asrepresented. RPS Energy reserves the right to review all calculations referred to or included inthe said reports and, if considered necessary, to revise the estimates in light of erroneous data




1.0 INTRODUCTION

1.1 Background and Historical Descriptio n

Maurel et Prom (“M&P”) and Wentworth Resources Limited (“Wentworth”) own working interestsin the Mnazi Bay Development Licence in Tanzania (Figure 1-1). M&P, the Operator of theconcession, owns its interests through its local subsidiary, M&P Exploration and ProductionTanzania Ltd and a share of Cyprus Mnazi Bay Limited (“CMBL”). Similarly, Wentworth owns anon-operating working interest in the Tanzanian legal entity Wentworth Gas Limited and a shareof CMBL. The other working interest owner in the Licence is the national oil company, theTanzania Petroleum Development Corporation (“TPDC”).




Asset Working Interes t StatusLicenceExpiryDate

Licence Area Comments

Mnazi BayPSA and

DevelopmentLicence,Tanzania

Maurel et Prom

48.060% production60.075% exploration

Production,Development

andExploration

October26, 2031 756 km 2

Small fielddevelopment currently

on production. Additional exploration

and developmentpotential

WentworthResources Ltd

31.940% production39.925% exploration

Table 1-1: Summary Table of Assets

The Mnazi Bay Concession is located at approximately 10 ° 19’ South and 40 ° 23’ East, on thesouth-eastern coast of Tanzania, just north of the border with Mozambique. (Figure 1-2)

In 1982, a gas field (Mnazi Bay) was discovered on the concession by AGIP, who drilled thediscovery well Mnazi Bay #1 (“MB-1”) on a seismically-defined structure. The objective of thewell was to identify the stratigraphic column and focus on a Lower Cretaceous oil target. Thewell was evaluated as having oil and gas in several potential reservoir zones and was drill stem




implement the other aspects of the GTP project. On October 26, 2006 the Tanzanian Ministry ofEnergy and Minerals granted a Development Licence to TPDC covering one discovery blockand eight adjoining blocks, which comprise the Mnazi Bay Contract Area covering the samearea as the original PSA Exploration Licence. The Development Licence has an initial twenty-five year term to 2031), and may be extended under certain conditions.




an associated 18-megawatt electric power generation facility located at Mtwara. The powerfacility generated first electricity on December 24, 2006, fuelled by gas production from theMnazi Bay Field. Commissioning of the Mnazi Bay gas processing facility and tie-in connectionto the Mtwara area power generating facility was completed on March 5, 2007, and since thattime, production delivery has steadily increased from approximately 0.5 MMscf/d to over2 MMscf/d in 2014.

In November 2009, Artumas completed a sale of a portion of its interest in the Mnazi BayLicence to Maurel et Prom S.A. and Cove Energy Tanzania Mnazi Bay Ltd., and On December

1, 2009, Maurel et Prom assumed operatorship. In September 2010 Artumas completed theprocess of changing its name to Wentworth Resources Limited, and then in July 2012, the CoveEnergy interest in the licence were purchased by Maurel et Prom and Wentworth, resulting inthe share ownerships in place at the effective date of this report.

1.2 Scope

This evaluation covers the gas reserves within the Tertiary formations within the Mnazi Baylicence, Tanzania

1.3 Data Sources

RPS has based this reserves assessment on publicly-available basin data, data supplied byboth Maurel et Prom and Wentworth and work previously carried out by RPS and itspredecessor company, APA Petroleum Engineering Inc.

Key data and reports which form the basis of RPS’ estimates are as follows:




1.5 Reserve Definitio ns

Reserves detailed in this report have been assessed using the Resource definitions aspublished by COGEH, the Society of Petroleum Engineers, World Petroleum Counc il, American

Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers 1.




2.0 CONCESSION AREAS

2.1 Mnazi Bay Lic ence, Tanzania

The Mnazi Bay Concession Area is located in south-eastern Tanzania in the Ruvuma(alternately-spelled Rovuma) Basin. The concession area is a 756 square kilometre block thatholds Tertiary, Cretaceous and Jurassic hydrocarbon potential (Figure 2-1). The discoveredTertiary-aged Mnazi Bay and Msimbati fields and extensions are defined by relatively sparseand variable quality 2D seismic data and by good quality 3D data over the offshore portion ofthe licence. Five wells have been drilled on the concession to date; four in the Mnazi Bay field(MB-1, MB-2, MB-3 and MS-1X) and one exploration well, Ziwani-1, which was non-commercial.

Additionally, several exploration prospects have been identified on the licence, however theseprospects are outside of the scope of this reserve evaluation.




Figure 2-2: Mnazi Bay show ing Mnazi Bay/Msimbati Field




contains detailed cost recovery and profit sharing arrangements and production royalty paymentobligations.

2.1.2 Mnazi Bay Licence Block Exploratio n History

The Mnazi Bay gas field was discovered in 1982 by AGIP. The first well Mnazi Bay #1 (“MB-1”)tested gas from the Miocene formation at rates of 13 mmcf/d. After testing, the well wassuspended by AGIP, due to lack of gas markets at the time. The concession was subsequentlyrelinquished by AGIP. The licence was acquired by Artumas (now Wentworth) in 2004. In 2005,

following reprocessing and acquisition of additional 2D seismic data, the MB-1 well wasre-entered and three gas discovery wells were drilled, MB-2, MB-3 and MS-1X. Two additionalseismic programs were shot in 2007 and 2008 by Artumas (now Wentworth).

Maurel et Prom assumed operatorship of the Mnazi Bay PSA during 2009. A 3D seismic datasurvey covering the offshore portion of the block was recorded and processed during 2012 /2013. . In 2013 a 328 km2 3D offshore seismic survey was conducted, and in 2014 anadditional 315 km of 2D onshore seismic and 58 km of high resolution onshore seismic datawas collected.




3.0 REGIONAL GEOLOGY AND PETROLEUM SYSTEM

3.1 Regional Geolog ical Setting

The Mnazi Bay Licence area in Tanzania is located in the northern part of the Ruvuma(“Rovuma” in Mozambique) Basin which straddles the border between Tanzania andMozambique. It is one of numerous basins along the east coast of Africa, formed when thepaleo-continent of Gondwana rifted apart during the Permian, Triassic and early Jurassic.Regionally, the rifting associated with the formation of the Ruvuma Basin led to the separation ofthe island of Madagascar from the main body of Africa.




and basin subsidence during the Tertiary, with the early centre located towards the northern partof the Ruvuma Basin. These sediments have been subjected to intensive gravity-drivendeformation, shale diapirism and slumping. The Ruvuma Delta complex comprises of a thick,eastwardly prograding wedge of rapidly deposited clastic sediments which extends eastwardinto canyon/channel sediments, forming a complex network of stacked channel sandstones.Resources are contained in this Tertiary interval, primarily in the Miocene and Oligocene.

The stratigraphy in the area is shown on the following chart:




3.2 Tertiary Depositio nal Environ ments

The Tertiary sequence in the Mnazi Bay area is situated within the canyon slope setting(Figure 3-3); these turbiditic canyon-fill deposits contain sandstones, which provide goodreservoirs, and shales, which enable stratigraphic traps. Onshore Mozambique Tertiary depositsare fluvial, deltaic deposits and marine shelf deposits (Figure 3-4), which make excellentreservoirs. In Offshore Area 1, Tertiary sediments consist of channel and deepwater fandeposits, which contain excellent quality reservoir sands; hydrocarbons are trapped on toethrust structures. (Figure 3-3 and Figure 3-4).




Figure 3-5 below shows the correlation between three wells on-shore Tanzania and on-shoreMozambique demonstrating the Upper and Lower Tertiary depositional cycles across theRuvuma (Rovuma) Basin.

Figure 3-5: Cross Section across On-Shore Tanzania and Mozambique Showin gUpper and Lower Tertiary Environments and Reservoir/Seal Pairs

Source: Cove Investor Presentation (May 2011)




Figure 3-6: Evolution of the Ruvuma Basin with Stratigraphic UnitsSource: Artumas Internal Presentation

3.4 Cretaceous Stratigraphy

An Early Cretaceous regression resulted in Lower Cretaceous deposition dominated bycontinental clastics on the western flank of the basin in the Maconde Formation passing laterallyto shallow marine deposits to the east. The Maconde Formation consists of fluvial




recent discoveries on the Offshore Area 1 Block are not available. Analogues from other East African margin basins have been used to describe the source rock potential of the RuvumaBasin. Known source rocks, along the East African margin, range from Permo-Triassic throughJurassic to possibly Cenozoic age. The source for the Mnazi Bay and Msimbati gas discoveriesis thought to be the regionally extensive mature Jurassic source rocks.

Results of 1D basin modeling from across the Ruvuma Basin indicate that peak oil generationfor mid-Jurassic source rocks was during early-mid Cretaceous times, while remaining potentialsource rocks in the Late Jurassic, Cretaceous and younger sections, which saw majorhydrocarbon generation and expulsion during the Eocene, Oligocene, and Recent epochs. Thelatter is triggered by the initiation of the Late-Tertiary to Recent East African Rift Valley systemwhich resulted in subsidence and a major heating phase pulse throughout the Ruvuma Basin.

3.6 Structure

Two episodes of deformation dominate the structural history of the Ruvuma Basin. Duringrifting, a NNE-SSW trending system of horsts and grabens developed, affecting pre-UpperJurassic strata. These strata dip regionally eastward due to loading of the passive margin.Gravitational collapse of passive margin sediments has resulted in the development of a linkedshelf-extensional and basinward toe-thrust system. Listric normal faults cut Tertiary strata andsole in a decollement near the top of the Cretaceous. The associated toe-thrust system islocated offshore to the east of the Mnazi Bay licence in Tanzania and offshore Mozambique.

Figure 3-7 shows the linked extensional system of roll over anticlines associated with normallistric growth faults, as found in Mnazi Bay and onshore Mozambique, and basinward toe thrustsystems which create structural traps for Tertiary plays in offshore Mozambique.




4.0 MNAZI BAY FIELD – RESERVES

The Mnazi Bay and Msimbati discoveries comprise the Mnazi Bay field and are the reservoirsare collectively referred to as comprising the Mnazi Bay Licence. The depositional model for thereservoirs is based on a stratigraphically complex series of stacked channels deposited in adeep-water canyon/slope setting.

4.1 Reservoi r Geology

4.1.1 Stratigraphy

Mnazi Bay and Msimbati reservoirs lie at the northern end of the Ruvuma Basin. The Ruvumabasin contains a shallow deltaic through deep slope succession. Reliable correlations withinsuch successions are difficult, as channelized, laterally-discontinuous reservoir sandstones,deposited in shallow deltaic through to deep slope settings, generally lack unique, correlatablecharacteristics.

Within the reservoir section, several correlation schemes can be envisioned between the MB-1,MB-2, MB-3, and MS-1X wells. The nature of the seismic anomalies at Mnazi Bay, indicate adeep water channel/canyon setting rather than a near shore deltaic environment. The reservoirsands are interpreted to have been deposited on the deepwater continental slope, as offsetstacked channel deposits and have been identified as occurring within four Miocene agedchannel sequences, the Lower Sand and Upper Sand for the Mnazi Bay reservoir section andthe Lower K Sand and Upper K Sand for Msimbati Field (Figure 4-1 and Figure 4-2). The sandunits were correlated using seismic and well logs and used channel scour, gas-water contactsand thickness and flooding surfaces to identify the channel sequences.




Figure 4-1: Mnazi Bay Stratigraphic Section

Upper MnaziTop

Upper MnaziBottom

Lower MnaziTop

Lower MnaziBottom

TVD Depth mSS

P r e v i o u s F o r m a t i o n

N a m e s










Figure 4-4: Line MB13-29 Showing the Mnazi Bay Channel




o MB Upper Sand Isopacho MB Lower Sand Isopach

o Gross Thickness above GWC

o Upper K Sand Isopacho Lower K Sand Isopach

Figure 4-5 and Figure 4-6 are examples of these maps. All the maps are included in

Appendix 2.




Figure 4-6: Mnazi Bay - Upper Sand Isopach above GWC




• Vsh < 0.50,• Φe > 0.08, and • Sw < 0.60

A composite of the logs from the four wells is shown in Figure 4-1 and Figure 4-2 of Section 4.1.The input values used to define the distributions for the probabilistic volumetric assessment aresummarized in Table 4-1.

Table 4-1: Log Evaluation Summary

4.2 Reservoi r Fluids

4.2.1 Pressure vs. Depth Relation ship s

In all four wells, reservoir pressure has been measured and interpreted at various sand depth

MS UPPER P90 P50 P10 Mean Distrib. MS LOWER P90 P50 P10 Mean Distrib.N/G 0.06 0.13 0.20 0.13 Normal N/G 0.20 0.35 0.50 0.35 Normal

Porosity 0.20 0.25 0.30 0.25 Normal Porosity 0.15 0.185 0.22 0.185 NormalSw 0.35 0.45 0.55 0.45 Normal Sw 0.41 0.51 0.61 0.51 Normal

MB UPPER MB LOWERN/G 0.15 0.23 0.31 0.23 Normal N/G 0.25 0.40 0.55 0.40 Normal

Porosity 0.16 0.21 0.26 0.21 Normal Porosity 0.18 0.21 0.24 0.21 NormalSw 0.26 0.34 0.42 0.35 Normal Sw 0.24 0.33 0.42 0.33 Normal




Figure 4-7: MB-01 RFT Pressure vs. Depth

6000

6200

6400

6600

6800

7000

72002900 2950 3000 3050 3100 3150 3200 3250 3300 3350 3400

T V D

( f t S S )

Pressure (psia)

MB-01

RFT Pressure vs Depth

Gas

Water

Lin ear (Water)

Lower Mnazi Gas

Lower Mnazi

Gas Gradients : 0.0580psi/ftWater Gradient: 0.438psi/ftWater Gradient:0.460psi/ft

Lower Mnazi GWC: 6215-6250ft (1894.3-1905.0m)




Figure 4-9: MB-03 RFT Pressure vs Depth

5500

6000

6500

7000

7500

80002800 2900 3000 3100 3200 3300 3400 3500 3600

T V D ( f t S S )

Pressure (psia)

MB03RFT Pressure vs Depth

Gas

Water

Upper MnaziGas

Lower Mnazi

Water

Upper MnaziGas Gradient: 0.0520psi/ftLower Mnazi Gas Gradient: 0.0580psi/ft

Water Gradient: 0.438psi/ft

Upper Mnazi Sands GWC - 6126ft (1867.3m)Upper Mnazi

Lower Mnazi

Lower Mnazi GWC - 6252ft (1905.5m)

MS1XRFT Pressure vs Depth




4.2.2 Gas Water Contact Depths

The depths of the gas water contacts (“GWC”) in the Mnazi Bay and Msimbati fields have beenestimated based on various interpretations of well test data, pressure gradient analyses fromthe repeat formation tester (“RFT”) data, and well log interpretation data. Although someuncertainty remains in the estimated GWC depths, it appears that there are two main GWClevels in the classic sands, and two GWC levels in the Upper Msimbati K sands. These sets ofGWC levels can be seen on the composite RFT plot shown below:

4500

4700

4900

5100

5300

5500

5700

5900

6100

T V D

( f t S S )

Mnazi Bay & Msimb atiComposite RFT Pressure vs Depth

MB01 Gas MB0 2 Ga s

MB03 Gas MS1 X Gas

MB01 Water MB02 Water

MB03 Water MS1X Water

Upper Msimbati

Lower Msimbati

Upper Mnazi

Lower Mnazi

Upper Msimbati GWC -5226ft

Lower Msimbati GWC -5359ft




The data used in determination of GWC depths for the field are summarized in Table 4-2:

MB#1 MB#2-ST2 MB#3 MS-1X

KB Elevation (ft above msl) 44 43 44 44

GWC Evidence

Well LogsU. Msimbati: GWC @ 5358ftSS (1633.1 mSS)

No GWC on logsU. Mnazi: GWC >6074 ftSS(1851.4 mSS) and < -6082ftSS (-1853.8 mSS)

L. Mnazi: GWC @ 6249 ftSS(1904.7 mSS)

L. Mnazi: GWC @ 6252 ftSS(1905.6 mSS)

Test Data

U. Msimbati: tested cleangas to mid point of K1 sands@ 5085 ftSS (1549.9 mSS)

U. Mnazi: produced cleangas to 6066 ftSS (1848.9mSS)

L .Mnazi: tested clean gas to6218 ftSS (1895.2 mSS)

L. Mnazi: Water and gas producedinterval 6214 ftSS to 6253 ftSS (1894to 1906 mSS)

L. Mnazi: tested clean gas to6251 ftSS (1905.3 mSS)

GDTU. Msimbati: 5082 ftSS(1549.0 mSS)L. Msimbati: 5355 ftSS(1632.2 mSS)

L. Mnazi: 6218 ftSS (1895.2mSS)

L. Mnazi: 6249 ftSS (1904.7 mSS) L. Mnazi: 6251 ftSS (1905.3mSS)

Mnazi Bay and Msimbati Gas Fields - all depths listed as subsea depthGas Water Contact Depths




establishes a gas-down-to (“GDT”) depth of -6218 ftSS (-1895.2 mSS) and -6251 ftSS

(-1905.3 mSS) in each of these two wells respectively.

The GWC depths interpreted from RFT pressure data is more interpretive, and therefore lesscertain than those from well tests and logs, due to the uncertainties in pressure datameasurements and the extrapolation of pressure gradient intersection lines associated with RFTtests. For example, in the case of the Lower Mnazi Bay sands RFT interpreted GWC depthof -6236 ftSS (-1900.7 mSS) in MB-2, this depth is shallower than a clearly defined GWC depthas seen on logs and confirmed by well testing. The interpreted depths and ranges of depthsfrom RFT tests are shown for each of the four wells on Figure 4-11.

Recognizing the inherent uncertainty in the GWC depths, where measured or inferred depthsare very similar across different sands, they have been grouped. For the purpose of thisresource evaluation, RPS has selected a set of GWC depths as summarized in the Table 4-3.The ‘gas down to’ (GDT) depth, the maximum depth at which gas was observed, is also shownin the table for reference.

Further, for the purposes of this resource assessment, RPS has assumed that the GWC depths

are uniform within each of the respective sands.

(mSS) (ftSS) (mSS) (ftSS) (mSS) (ftSS) (mSS) (ftSS)Msimbati Upper K 1593.0 5226.3 1549.0 5082.0Msimbati Low er K 1633.4 5358.9 1632.2 5354.9Msim bati NE 1613.2 5292.6 1864.0 6115.4 1905.3 6250.9Msim bati NE Exten sion 1613.2 5292.6 1864.0 6115.4 1905.3 6250.9Mnazi Upper 1864.0 6115.4 1851.0 6072.8

Gas Down ToGas:Water Contact

FormationLo w Probable High




liquid volumes were reported in the separator during any of the flow tests. A summary of the lab

measured compositional gas analyses is shown in Table 4-4.

Table 4-4: MB-2 Gas Compos ition

In the series of DST tests on MB-3, the on-site gas analyses indicated slightly richer gas in theLower Mnazi Bay sands from 6202 – 6251 ftSS, previously referred to as the C sands. These

DST # 1 2 3 4 5

SandIn terval 6300 - 6340 6220 - 6230 5920 - 5940 5798 - 5812 5578 - 5592SG 0.6276 0.5661 0.5738 0.5738 0.57

H2 0.07 0 0 0 0

N2 0.19 0.18 0.19 0.19 0.19CO2 0.28 0.18 0.3 0.24 0.32

H2S 0.02 0 0 0 0

C1 97.98 98.19 98.05 98.11 98.04

C2 1.01 1.01 1.02 1.02 1.02

C3 0.28 0.28 0.28 0.28 0.28

IC4 0.05 0.05 0.05 0.05 0.05

NC4 0.05 0.06 0.06 0.06 0.06

IC5 0.01 0.02 0.01 0.02 0.01

NC5 0.01 0.01 0.01 0.01 0.01

C6 0.02 0.01 0.02 0.01 0.02

C7+ 0.03 0.01 0.01 0.01 0

Total 100.0 100.0 100.0 100.0 100.0

Low er Mnazi Upper Mnazi

MB-2 Gas Compositio n Analysis (Mole %)




Table 4-5: MB-03 Gas Composition

During the extended production testing on all four wells minor volumes of liquid hydrocarbonwere produced. The measured producing oil:gas ratios (“OGR”) were all too small to bemeasured on a daily basis, and have been summarized for the duration of each of the extendedproduction tests in Table 4-6:

DST # 1 2 3 4SandInterval (ft) 6246-6295 6110-6180 5795-5842 5692-5760SG 0.6276 0.5661 0.5738 0.5738H2 0.01 0 0 0N2 0.02 0.01 0.63 0.63CO2 0 0 0 0H2S 0 0 0 0C1 89.88 98.37 96.18 96.18C2 6.62 1.17 3.08 3.08C3 2.42 0.31 0.01 0.01IC4 0.43 0.06 0 0NC4 0.62 0.07 0 0IC5 0 0 0 0NC5 0 0.01 0 0C6 0 0 0.07 0.07C7+ 0 0 0.03 0.03

Total 100.0 100.0 100.0 100.0

Lower Mnazi

MB-3 Gas Composition Analysis (Mole %)

Upper Mnazi

Extende d Well Testing - Fluid Produ ction Summ ary




Figure 4-12: Mnazi Bay (MB-02-ST2) Gas PVT

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.1

0.9

0.91

0.92

0.93

0.94

0.95

0.96

0.97

0.98

0.99

1

0 500 1000 1500 2000 2500 3000 3500 4000 4500

B g

( r e s m

3 / s m

3 )

Z f a c

t o r

Pressur e (psia)

Mnazi Bay Gas PVT

Z Factor

Bg




The following table summarizes the test production rates in each of the wells 13 14 1516 .

Table 4-7: Mnazi Bay & Msimbati Fields Well Test Summary

Further details of the above test interpretations are shown in Table 4-8. All of the above testswere conducted with low sandface pressure drawdown. The tests confirm substantialdeliverability potential in each of the wells and each of the reservoir sands.

SandsDepth (ftSS) DST Depth (ftSS) DST EWT Depth (ftSS) DST EWT Depth (ftSS) DST EWT

Upper Msimbati - - - - - 4798.2 - 4820.0 9.2 -- - - - - 4889.41- 4951.5 9.6 9.4- - - - - 5101.8 - 5152.7 9 -

Upper Mnazi - 5500.5 - 5514.3 7.84 - - - - -- 5717.6 - 5731.4 8.71 - 9.33 11.1 - -- 5838 - 5731.4 8.44 11 5735 - 5812 14.57 - 6040 - 6080 10.1 -

Lower Mnazi 6147.3 - 6172.3 10.5 - - - - - -6132.4 - 6146.3 8.29 - 6080 - 6150 13.95 - - -

- 6213.6 - 6253.1 1.25 - 6216 - 6265 11.84 - - -

MB#2-ST2

Mnazi Bay & Msimbati Drill Stem Test and Extended Well Test SummaryWell Test Flow Rate (MMcf/d)

MB#1 MS-1XMB#3

MB#1

DST# Sands

TestInterval

Top

TestIntervalBottom

TestInterval

TestedInterval Net

PaySandface

Drawdown

Final GasProduction

Rate Pi kg h AOF(TVD ftSS) (TVD ftSS) (ft) (ft) (psia) (MMcf/d) (fraction) (psia) mD-ft MMcf/d

Lower Mnazi 6,109 6,121 12commingled 39 131 10.5 0.20 2,992 1,638 n/a

Lower Mnazi 6,188 6,218 30

MB#2-ST2

DST# Sands

TestInterval

Top

TestIntervalBottom

TestInterval

TestedInterval Net

PaySandface

Drawdown

Final GasProduction

Rate Pi k h AOF




The well MB-01 was re-entered for the purpose of testing in March 2005. The existing cement

and bridge plugs were drilled out and the well perforated in the Upper and Lower Mnazi Bay atthe following intervals:

• Lower Mnazi Bay:o 6232 – 6262 ftKB (6188 – 6218 ftSS), Zone Do 6150 – 6170 ftKB (6106 – 6126 ftSS), Zone E

• Upper Mnazi Bay:o 5962 – 5992 ftKB (5918 – 5948 ftSS), Zone Fo 5803 – 5813 ftKB (5759 – 5769 ftSS), Zone G

A dual packer with dual string (2 3/8”) tubing with sliding sleeves was installed. This allowscommingled production from the perforations in the Lower Mnazi Bay (D & E) through the longstring and production from either of the Upper Mnazi Bay intervals through the short string,installed with a sliding side door. Since the F Zone produced water during production testing,the Upper Mnazi Bay production is limited to the Zone G perforations.

4.4 Production History

The Mnazi Bay field was put onstream beginning in January 2007 and production has beenmore or less continuous ever since. Production has occurred from both the lower and upperzones (D/E and G) in MB-01, and since mid-2012 from the F Zone in MB-03. Natural gasproduced is currently processed and pipelined to the town of Mtwara where it is used as the fuel




Production allocation from the two tubing strings has recently been updated based on pressure

measurements at the end of 2012, following a determination that the short and long strings hadbeen mis-labelled and production consequently wrongly assigned. For the sake of clarity andavoidance of confusion with previously published accounts, the production from each of theproduction intervals/strings is shown below in Figure 4-14 and Figure 4-15.

Figure 4-14: MB-1 Zone D/E Produc tionHistory

Figure 4-15: MB-1 Zone G Produc tion Histor y

Recent production, from MB-3, Zone F is shown in Figure 4-16.

0.0E+00

5.0E+05

1.0E+06

1.5E+06

2.0E+06

2.5E+06

3.0E+06

3.5E+06

4.0E+06

2,000

2,100

2,200

2,300

2,400

2,500

2,600

2,700

2,800

R a t e

( s c f / d )

P r e s s u r e ( p s i a )

MB-1 D/E daily production history

Gas ratescf/d

THP psia

30/06/2011Shut in for PBU

12/10/2012Shut in for PBU

0.0E+00

5.0E+05

1.0E+06

1.5E+06

2.0E+06

2.5E+06

3.0E+06

3.5E+06

4.0E+06

0

350

700

1050

1400

1750

2100

2450

2800

R a t e

( s c f / d )

P r e s s u r e ( p s i a )

MB-1 G daily production history

Gas rate(scf/d)

THP psia Pressure transmitterreplaced Mar 2009

MB-3 F daily production history




RPS has reviewed the aforementioned information, interpretations and data and is of the

opinion that the data are reasonable. However, all data has been accepted as presented andhas not undergone due diligence to verify its accuracy.

4.5.1 Reserves Determin ation Method olog y

A volumetric probabilistic methodology has been utilized to determine in-place volumes. Theinputs for the probabilistic analysis are comprised of:

•

Gross Rock Volumes: determined from the geo-statistical static reservoir model.• Net/Gross pay ratio: determined by statistical analysis of the log evaluations, by layer,

for each of the four wells.• Porosity: determined by statistical analysis of the log evaluations, by layer for each of the

four wells.• Water Saturation: determined by statistical analysis of the log evaluations, by layer for

each of the four wells.• Gas Formation Volume Factor: determined from pressure, temperature and gas analysis

data from each of the four wells.• Recovery Factor: determined through production forecasting by material balance, taking

into account well deliverability and surface network constraints through the newly builtfacilities in 2015.

4.5.2 Gross Rock Volume




4.5.3 Init ial Hydrocarbon s in Place (GIIP)

GIIP volumes for the Mnazi Bay field were derived probabilistically using Logicom’s REP TM

software and the following variables:

• Gross rock volume (“GRV”): GRVs for each sand package were calculated by thecreation of polygons limited by the interpreted channel belt facies, the GWCs and theextent of the seismic amplitude anomalies as discussed above. A beta distribution wasutilized for the GRV for each layer.

•

Net to Gross ratio (“N/G”): A normal distribution for each of the sand packages wasutilized, with the P 90 and P 50 input values constrained by results derived from thepetrophysical analyses for each layer at each well.

• Water Saturation (“S w”): Normal distributions defined by P 90 and P 50 input valuesconstrained by results derived from the petrophysical analyses for each layer at eachwell.

• Gas Formation Volume Factor (1/B g): A normal distribution was used, with the P 50 input

value for each formation based on a dry gas molecular weight of 16, plus pressure andtemperature data derived during the well tests. Values for 1/B g ( equivalent to E g) varybetween 154 in the MS Upper and 171 in the MB Upper horizons.

A summary of the input ranges and distributions used for the probabilistic analysis is shownin Table 4-10.

MS UPPER P90 P50 P10 Mean Distrib. MS LOWER P90 P50 P10 Mean Distrib.GRV 567 891 1587 1049 Beta GRV 31 37 43 37 Beta




Mnazi Bay & Msimb ati Gas Initially in Place

Field P 90 P 50 P 10 Mean

Bscf Bscf Bscf Bscf

MS Upper 35 90 187 103

MS Lower 3.2 6.1 10 6.4

MB Upper 133 257 435 273

MB Lower 126 251 423 265

Total * 413 635 910 651* Totals determined probabilistically and do not sum arithmeticallyexcept at the mean values

Table 4-11: Mnazi Bay GIIP Volumes (Bscf)

4.5.4 Technically Recoverable Reserves

The volume of gas ultimately recoverable is a function of both technical factors governing theflow rates and gas deliverability of the gas reservoirs and economic factors governing thecommerciality of potential gas recovery schemes. This section describes the methodology todetermine the technical recovery factors for the reservoirs. When economic limits are applied,the volumes may be less than the technical recoverable volumes presented here.

The ultimate technical gas recovery for the Mnazi Bay Field has been estimated using materialbalance calculation of reservoir pressure depletion, based on Petroleum Experts (PETEX)MBALTM reservoir models and PROSPER TM well models linked together with GAP TM and using




Further to this, an estimation of the downhole pressures, using SPIDR TM technology (tubing

head pressure measurement), in well MB-1 was made prior to the shut in of the well in 2012.The material balance estimate (p/Z vs gas production) is shown in Figure 4-17.

Figure 4-17: MB-1 Low er Mnazi Bay (DE Sands) Material Balance (p/Z vs. Gp)

Again, the estimate remains uncertain given the still limited offtake and the potential inaccuracyof extrapolating pressures from surface. Nevertheless, a GIIP value of approximately 400 Bcf(close to the 3P estimate for the Lower Mnazi Bay) is indicated. This certainly gives confidencethat the low case estimate may be exceeded but may also indicate communication between thedifferent reservoir zones away from the wells.

4.5.5 Product ion Forecasting

3,200

3,210

3,220

3,230

3,240

3,250

3,260

0 1 2 3 4 5

p / Z

( p s i a )

Cumulative Gas Production (Bcf)

MB-1 Lower MB Material Balance (detail)

Historical Data

Best Fit

Worst Case

0

500

1000

1500

2000

2500

3000

3500

0 100 200 300 400 500

p / Z

( p s i a )

Cumulative Gas Production (Bcf)

MB-1 Lower MB Material Balance

Historical Data

Best Fit

Worst Case




Figure 4-18: Mnazi Bay Gas Export Schematic




The inlet pressure to the CPF at Madimba will be 94 barg (1,378 psia). For forecasting, RPS

has assumed that the delivery pressure at the Mnazi Bay facilities will be 1,450 psia. Followingcompression, RPS assumes that the pressure through the facilities will be dropped to 30 barg(450 psia).

GAP TM models were created to simulate production for deterministic PDP, 1P, 2P and 3P cases,based on the probabilistic GIIP ranges. An example of the GAP TM model set-up is shown inFigure 4-20.




West EastCase MB-1 MB-2 MB-3 MB-4 MB-5 MSX-1

K3K2K1

MS Lower K0I

HGF

D-EC

K3K2K1

MS Lower K0IHGF

D-EC

K3K2

MS Upper

MB UPPER

MB LOWER

MB LOWER

Development Plans Breakdown

PDP

MS Upper

Central

MS Upper

MB UPPER

Layer

1P




Further to this, the different reserves cases allow for disconnection of the different areas of the

field through faulting observed on seismic. The PDP and 1P cases separate the west part of thereservoirs (penetrated by MB-1) from a central area (MB-2 and -3) and an eastern area (MS-1X)which is not accessed except in Zone F. The 2P case connects the eastern area so far as it isvolumetrically-defined and the 3P case assumes no fault compartmentalization.

The PDP case assumes access only to zones currently connected through the completions(including access by slickline operation of sliding-sleeve side doors). The other cases assumeworkovers and additional perforations (with associated Capex) for zones that have been shownto be gas-bearing and productive.

Well deliverability was based on well test interpretations where available (most zones in theexisting wells). Negative skin was interpreted in the majority of the tests but improvements thatcould be made by additional or repeat perforation were assumed in the further developmentcases. Estimates of non-Darcy skin were included since production rates are expected to behigh and exceed 10 MMscf/d in many cases; turbulent flow is expected. For the new intervals(new wells), reservoir properties were based on averages of existing wells. A permeability vsporosity relationship was developed based on zonal porosity and well test permeability values.

Tubing lift was included in the models using PROSPER TM and the Petroleum Experts 3correlation.

The forecasts were run assuming ramping up of the production through 2015, achieving80 MMscf/d (minimum expected) total field production by June 15, 2015 and the maximumofftake specified in the GSA of 130 MMscf/d by the beginning of 2016. Workovers, perforationsand new wells were scheduled to maintain the plateau of 130 MMscf/d as long as possible, withplanned compression starting in January 2018. The resulting production rate and cumulative




Figure 4-23: Mnazi Bay Field Cumulative Gas Produc tion Forecast

The above forecasts yield the following technical recoveries and recovery factors.

Case GIIP (Bscf) EUR (Bscf) Rec. Factor

0

100

200

300

400

500

600

700

800

C u m u l a t i v e G a s P r o d u c t i o n

( B s c f )

3P

2P

1P

PDP




5.0 ECONOMICS AND RESERVES

An economic evaluation has been carried out based on the forecast volumes in Section 4 andtheir associated development plans, with the objective of determining the net-entitlement,reserves and NPV for each working interest owner company. The 2004 PSA and 2014 GasSales Agreement were used to provide the fiscal constraints to the evaluation. An economicspreadsheet model, as supplied by the Operator was modified to be suitable for reservesevaluation; upgrades were made to correctly account for, amongst others, repaymentschedules for TPDC carry amounts, cash flow splits for all stakeholders, taxation and alternativegas delivery prices to arrive at a valid evaluation of entitlement reserves for each party.

From the output of the model, the net cashflow was used to derive NPV values at variousdiscount rates for the different reserves categories. Working interest entitlement reserves werecalculated based on SPE and COGEH reserve definitions and guidance as follows:

• Gross Reserves were calculated as the product of total sales production volumes andthe company working interest.

• Net Reserves were calculated as the product of the field gross sales volumes and theratio of the company’s summation of net Cost and Profit Petroleum revenue to the fieldtotal gross sales revenue.

5.1 PSA and Developm ent Licence

The development Licence, issued in October 2006, provides the right for the concession holdersto develop the Mnazi Bay Field according to the 2004 PSA and within the same exploration




Increments of Daily Natural

Gas Production (MMscf/d)TPDC Share Company Share

0-2.52.5-5.0

5.0-10.0 Above 10.0

50% less Adjustment Factor60% less Adjustment Factor65% less Adjustment Factor70% less Adjustment Factor

50% plus Adjustment Factor40% plus Adjustment Factor35% plus Adjustment Factor30% plus Adjustment Factor

The “Adjustment Factor” is an amount of Profit Petroleum, the value of which is equal to theamount necessary to fully pay and discharge all liability of the Company for Tanzanian taxes.The Company assigns to the Government an amount of its share of Profit Petroleum equal tothe Adjustment Factor as security to the Government for the payment of the Company’s liabilityfor Tanzanian taxes.

Hence, the net tax effect from an NPV perspective on the Company is zero and the tax iseffectively paid from the TPDC share of Profit Petroleum. From a reserves perspective,however, since the income tax is paid as a share of Profit Petroleum, the Adjustment Factor isincluded as net reserves entitlement.

5.2 Company Ownership and Working Interest

Both Maurel et Prom and Wentworth Resources hold their respective interests through acombination of Tanzanian legal entities and Cyprus Mnazi Bay Limited (in their respectiveshares).

TPDC has a 20% interest in the development licence but is carried for exploration.




Maurel et Prom

60.075%

Wentworth Resources Limited

39.925%

M&P Exploration andProduction Tanzania Ltd

47.775%

Cyprus Mnazi Bay Limited Wentworth Gas Limited

31.75%12.30% 8.175%

Mnazi Bay Exploration Licence (TPDC Carry)

Table 5-2: Mnazi Bay Exploration Licenc e Company Interests

5.3 Product Price

Two different sales prices are applicable to gas produced from Mnazi Bay. Firstly, gas will besold to TPDC for the supply gas to Dar Es Salaam via Madimba, under a recent gas salesagreement signed on September 12, 2014 between TPDC and the Mnazi Bay working interestowners (also including TPDC). Secondly, the owners plan to continue selling (approximately2 MMscf/d) gas to Tanzania Electric Supply Company Limited (“TANESCO”), as fuel for thelocal Mtwara power facility based on the existing gas price.

The GSA for supply to Dar Es Salaam via the CPF at Madimba specifies raw gas volumes tothe delivery point at the downstream flange of the 16” pipeline at the Mnazi Bay Facilities.

Mtwara




Given the presently existing uncertainty in volumes, and deliverability of new well(s), the

contract provides for flexibility in the nominated contract quantities for delivery and outlines theprocedures for the nominations. The sellers are required to make available up to 80 MMscf/d,with the potential for this to be increased to 130 MMscf/d, for the buyer to nominate. There is atake-or-pay minimum delivery based on 85% of the nominated annual contract quantity.

The total gas price is based on three elements:

A. Gas Charge

B. Regulatory Charge

C. Other Charges

Total Gas Price = A + B + C US$/MMBtu

The Gas Charge (A) is initially set at US$3.00 / MMBtu and inflated at US CPI with first indexingon January 1, 2015.

The Regulatory Charge means any tariff, duty, levy or tax charged by any regulatory authorityand incurred by the sellers.

"Other Charges" means:

a) any taxes (except for the sellers' taxes) that are payable in connection with the sale anddelivery of gas under the agreement, including all taxes of an excise duty nature thatarise in relation to sale of the gas under the agreement; and/or




Gas has been sold to the local Mtwara power generation facility since 2007 at rates of up to

2 MMscf/d and at a price of $5.36 / MMBtu. It is expected that this will continue in parallel to theMadimba export since power generation will be required for the local population at Mtwara.

0

1

2

3

4

5

6

2015 2017 2019 2021 2023 2025 2027 2029 2031

G a s P r i c e

( $ / M M B t u )

Mnazi Bay Gas Price

GSA Gas Charge (A)

Gas Price to Mtwara (2 MMscf/d)

Average (Blended) Gas Price




The capex costs are shown in the cost summary tables for each reserves case in Tables 5.8

to 5.11.

5.5 Opex

The opex estimate as supplied by the Operator has been used in the economic calculation. Adetailed breakdown was provided which included G&A and indirect charges. This was reviewedand considered reasonable based on historical costs (bearing in mind that the development isbeing expanded). Operating costs are uncertain, especially following significant changes in

development.The costs are calculated based on a fixed and variable element. The fixed operating costsincrease by $1.6 million following installation of compression at the beginning of 2018, relatingto the increased maintenance costs. The total opex estimate is shown in Figure 5-2 andtabulated in Tables 5.6 to 5.9.

3

6

9

12

15

5

10

15

20

25

N u m

b e r o f W e l l s P r o d u c i n g

T o t a l O p e x

( m i l l i o n U S $ )

Total Opex (million US$) & Well count

PDP-Well Count

1P-Well Count

2P-Well COunt

3P-Well Count

PDP

1P

2P




recovery. A daily maximum of 1.4 MMcf/d has been proposed. For the purpose of the economic

evaluation, this gas is assumed to be sold at the contract price as part of the production stream.

5.7 Taxation

Tanzanian income tax is payable to GOT at 30% of taxable income. Taxable income is definedas the gross revenue less allowances. The allowances include opex and depreciation of capitalassets (property, plant & equipment and exploration & evaluation). The capital allowances arecalculated based on 5-year straight-line depreciation.

Local taxes are also payable to EWURA (Energy and Water Utilities Regulatory Authority) atapproximately 1% of gross revenue and through a city levy of 0.3% of gross revenue.

5.8 Existi ng Cost, Tax and TPDC Carry Pools

As of December 31, 2014, the status of the various carried-forward balances for cost oil, tax andrepayments by TPDC for its carry (prior to development) were as follows:

Cost Oil: Total value for the licence, remaining to be recovered from previous expenditure wasUS$264.54 million. This amount is shared between the Companies (including TPDC) inproportion to their working interests.

Tax: Each Company reports a different GOT income tax position dependent on the history oftheir involvement in the Concession. Tax loss carry forward balances included in this evaluationare US$176.5 million for Wentworth Gas Limited (Wentworth’s legal entity in Tanzania) andUS$3.517 million for CMBL, in which Wentworth holds a 39.925% interests. It is unlikely underthe currently envisioned development that these tax loss carry forward amounts will be retired




5.9 Reserves and Economic Results

The economic model was used to generate cash flow forecasts for each of the reserve casescenarios and to determine the economically recoverable reserves for each case. Detailed cashflow output summaries are presented for the four reserve levels in Tables 5.5 to 5.13 forWentworth’s working interest .

The reserve volumes for Wentworth Resources’ interest in the Mnazi Bay Field are summarizedin the table below:

Wentworth Resources Working Interest Reserves for Mnazi Bayas at December 31, 2014

RPS Forecast 2015-01-01

Reserve Category Oil Sales Gas NGL& C5 + BOE Oil Sales Gas NGL& C5 + BOE(MMstb) (Bscf) (MMbbl) (MMbbl) (MMstb) (Bscf) (MMbbl) (MMbbl)

PROVEDProducing - 26.5 - 4.4 - 20.7 - 3.5

Non Producing Undeveloped - 62.7 - 10.5 - 47.4 - 7.9Total Proved - 89.2 - 14.9 - 68.2 - 11.4

Probable - 52.3 - 8.7 - 27.3 - 4.5

PROVED + PROBABLE - 141.5 - 23.6 - 95.5 - 15.9Possible - 85.1 - 14.2 - 39.9 - 6.6

PROVED + PROBABLE + POSSIBLE - 226.6 - 37.8 - 135.3 - 22.6

Gross Reserves Net Reserves



US$/bbl US$/bbl %/annum

2015 3.00 5.36 2.0

2016 3.06 5.36 2.0

2017 3.12 5.36 2.0

2018 3.18 5.36 2.0

2019 3.25 5.36 2.0

Madimba GasCharge (A)

Mtwara PowerGeneration

Forecast Case

Forecast of Prices InflationGas Price Forecast 2015.01.01, Nominal Values

Year

Oil BenchmarksInflation Rate

Table 5.5



rpsgroup.com/canada 1

Table 5.6 Total Cost Summary Proved Developed Producing

Capex Summary ( Real 2015 US$) 2015 Year End Mnaz i Bay Reserve Review - Proved Developed Produc ing Case

Totals 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

DrillingFuture WellsMB-4 - - - - - - - - - - - - - - - - - - - - - - - MB-5 - - - - - - - - - - - - - - - - - - - - - - -

Total - - - - - - - - - - - - - - - - - - - - - - -

Existing WellsMB-1 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations - - - - - - - - - - - - - - - - - - - - - - - MB-2 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations - - - - - - - - - - - - - - - - - - - - - - - MB-3 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations - - - - - - - - - - - - - - - - - - - - - - - MSX-1 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations - - - - - - - - - - - - - - - - - - - - - - -

Wells Subtotal - - - - - - - - - - - - - - - - - - - - - - -

FacilitiesCompression - - - - - - - - - - - - - - - - - - - - - - - Madimba Facilities Upgrade - - - - - - - - - - - - - - - - - - - - - - -

Faciliti es & Other Subtotal - - - - - - - - - - - - - - - - - - - - - - -

Studies (G&G and Eng) Total - - - - - - - - - - - - - - - - - - - - - - -

Total Capex (Real 2015 US $) - - - - - - - - - - - - - - - - - - - - - - -

Aband onmen t Cos t (Real 2015 US $) 13.00 - - - - - 13.00

Opex Summary (Real 2015 US$)

Field Fix ed (includi ng G&A) 65.40 10.10 10.10 10.10 11.70 11.70 11.70

- - - - - - -

Field VariableWell count based ($/well/year) - 0.40 0.40 0.40 0.40 0.40 0.40

Prod based ($/MMBtu) - - - - - - -

- - - - - - -

Total Variable Opex (Real 2015 US $) 8.40 1.60 1.60 1.60 1.60 1.60 0.40

-- - - - - -

Total Opex (Real 2015 US $) 73.80 11.70 11.70 11.70 13.30 13.30 12.10




Table 5.7 Total Cost Summary Proved Developed + Undeveloped

Cap ex Su mm ar y ( Real 2015 US$) 2015 Year En d Mn azi Bay Res er ve Rev iew - To tal Pr ov ed Cas e

Totals 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

DrillingFuture WellsMB-4 21.10 21.10 - - - - - - - - - - - - - - - - - - - - - MB-5 - - - - - - - - - - - - - - - - - - - - - - -

Total 21.10 21.10 - - - - - - - - - - - - - - - - - - - - -

Existing WellsMB-1 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations - - - - - - - - - - - - - - - - - - - - - - - MB-2 Work-overs 5.10 - 5.10 - - - - - - - - - - - - - - - - - - - -

Re-perforations 0.20 - - 0.20 - - - - - - - - - - - - - - - - - - - MB-3 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations 0.40 - 0.40 - - - - - - - - - - - - - - - - - - - - MSX-1 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations 0.60 - 0.20 0.40 - - - - - - - - - - - - - - - - - - -

Wells Subtotal 27.40 21.10 5.70 0.60 - - - - - - - - - - - - - - - - - - -

FacilitiesCompression 40.00 - 8.00 20.00 12.00 - - - - - - - - - - - - - - - - - - Madimba Facilities Upgrade 17.94 17.94 - - - - - - - - - - - - - - - - - - - - -

Faciliti es & Other Subtotal 57.94 17.94 8.00 20.00 12.00 - - - - - - - - - - - - - - - - - -

Studies (G&G and Eng) Total 0.88 0.88 - - - - - - - - - - - - - - - - - - - - -

Total Capex (Real 2015 US $) 86.22 39.04 13.70 20.60 12.00 - - - - - - - - - - - - - - - - - -

Aband onmen t Cos t (Real 2015 US $) 13.75 - - - - - - - - - - - 13.75


Field Fix ed (includi ng G&A) 135.60 10.10 10.10 10.10 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70

Field VariableWell count based ($/well/year) - 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40

Prod based ($/MMBtu) - - - - - - - - - - - - -

To tal Var iab le Op ex (Real 2015 US $) 23.60 1.60 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00

- - - - - - -Total Opex (Real 2015 US $) 159.20 11.70 12.10 12.10 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70




Table 5.8 Total Cost Summary Proved + Probable

Capex Summary ( Real 2015 US$) 2015 Year End Mnaz i Bay Reserve Review - Total Proved + Probab le Case

Totals 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

DrillingFuture WellsMB-4 21.10 21.10 - - - - - - - - - - - - - - - - - - - - - MB-5 - - - - - - - - - - - - - - - - - - - - - - -

Total 21.10 21.10 - - - - - - - - - - - - - - - - - - - - -

Existing WellsMB-1 Work-overs 5.10 - - 5.10 - - - - - - - - - - - - - - - - - - -

Re-perforations - - - - - - - - - - - - - - - - - - - - - - - MB-2 Work-overs 5.10 - - 5.10 - - - - - - - - - - - - - - - - - - -

Re-perforations 0.20 - - - 0.20 - - - - - - - - - - - - - - - - - - MB-3 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations 0.40 - - - 0.40 - - - - - - - - - - - - - - - - - - MSX-1 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations 0.60 - 0.40 - - 0.20 - - - - - - - - - - - - - - - - -

Wells Subtotal 32.50 21.10 0.40 10.20 0.60 0.20 - - - - - - - - - - - - - - - - -




Total Capex (Real 2015 US $) 91.32 39.04 8.40 30.20 12.60 0.20 - - - - - - - - - - - - - - - - -

Aband onmen t Cos t (Real 2015 US $) 13.75 - - - - - - - - - - - - - - - - - 13.75


Field Fix ed (includi ng G&A) 205.80 10.10 10.10 10.10 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70

- - - - - - - - - - - - - - - - - - -

Field VariableWell count based ($/well/year) - 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40

Prod based ($/MMBtu) - - - - - - - - - - - - - - - - - - -

- - - - - - -

To tal Var iab le Op ex (Real 2015 US $) 32.40 1.60 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 0.40 0.40

Total Opex (Real 2015 US $) 238.20 11.70 12.10 12.10 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 12.10 12.10




Table 5.9 Total Cost Summary Proved + Probable + Possible

Capex Summary ( Real 2015 US$) 2015 Year End Mnaz i Bay Reserve Review - Total Proved + Probab le + Poss ib le Case

Totals 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

DrillingFuture WellsMB-4 21.10 21.10 - - - - - - - - - - - - - - - - - - - - - MB-5 30.00 - 30.00 - - - - - - - - - - - - - - - - - - - -

Total 51.10 21.10 30.00 - - - - - - - - - - - - - - - - - - - -

Existing WellsMB-1 Work-overs 5.10 - - - - 5.10 - - - - - - - - - - - - - - - - -

Re-perforations - - - - - - - - - - - - - - - - - - - - - - - MB-2 Work-overs 5.10 - - - - 5.10 - - - - - - - - - - - - - - - - -

Re-perforations 0.20 - - - - - 0.20 - - - - - - - - - - - - - - - - MB-3 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations 0.40 - - - - 0.20 0.20 - - - - - - - - - - - - - - - - MSX-1 Work-overs - - - - - - - - - - - - - - - - - - - - - - -

Re-perforations 0.60 - - - 0.20 - - 0.40 - - - - - - - - - - - - - - -

Wells Subtotal 62.50 21.10 30.00 - 0.20 10.40 0.40 0.40 - - - - - - - - - - - - - - -




Total Capex (Real 2015 US $) 121.32 39.04 38.00 20.00 12.20 10.40 0.40 0.40 - - - - - - - - - - - - - - -

Aband onmen t Cos t (Real 2015 US $) 20.75 - - - - - - - - - - - - - - - - - - - - - 20.75


Field Fix ed (includi ng G&A) 252.60 10.10 10.10 10.10 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70 11.70

- - - - - - - - - - - - - - - - - - - - - - -

Field VariableWell count based ($/well/year) - 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40 0.40

Prod based ($/MMBtu) - - - - - - - - - - - - - - - - - - - - - - -

To tal Var iab le Op ex (Real 2015 US $) 44.00 1.60 2.00 2.00 2.00 2.00 2.00 2.00 2.40 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00 2.00

Total Opex (Real 2015 US $) 296.60 11.70 12.10 12.10 13.70 13.70 13.70 13.70 14.10 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70 13.70

Table 5.10 Cash Flow Summary Proved Developed Producing (Wentworth )




ab e 5. 0 Cas ow Su a y oved eve oped oduc g (We two t )SUMMARY OF OIL AND GAS FIELD RESERVES, PRODUCTION AND CASHFLOW Production Forecast:

Proved Developed ProducingCOMPANY: Wentworth Resources Reserves Level: Proved Developed Producing RPS Forecast 2015-01-01

OPERATOR: Maurel et Prom Price Forecast Case: RPS Forecast 2015-01-01FIELD: Mnazi Bay Average Annual Cost Inflati on: 2.00%

COMPANY SHARE: 31.94% Effective Date:

RESERVES PRESENT VALUE - COMPANY SHARE (Million US$) ABANDONMENT AND RECLAMATION COSTSCompany Share, Net of Salvage Value

Gross Net Gross Net Discount Rate: 0% 5% 10% 15% 20%

Crude Oil (MMstb) - - - - Gross Revenue 87.1 78.6 71.6 65.8 60.8 Cost (Million US$): 4.58Sales Gas (BCF) 82.9 72.5 26.5 20.7 Net Revenue 68.3 61.5 55.9 51.3 47.3 Year: 2020NGL (MMbbl) - - - - Operating Costs 24.8 21.4 18.7 16.5 14.7Condensate (MMbbl) - - - - Capital Costs - - - - -

Cash Flow Before Tax 73.6 69.3 65.4 61.9 58.7Total BOE * (MMboe) 13.8 12.1 4.4 3.5 Cash Flow After Tax 72.7 68.5 64.7 61.3 58.2

Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035+PRODUCT PRICES (US$)

Field PricesCrude Oil (US$/stb)Sales Gas (US$/MMbtu) 3.08 3.13 3.21 3.33 3.55 3.78 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00NGL (US$/bbl)Condensate (US$/bbl)COST INFLATION (%/annum) 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0% 2.0%

COMPANY SHARE GROSS PRODUCTIONYear 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035+ Total

Production Wellcount (#) 4 4 4 4 4 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Annual Gros s Produc tion

Crude Oil (MMstb)Sales Gas (BCF) 6.96 7.28 6.00 3.59 1.64 1.01 - - - - - - - - - - - - - - - -NGL (MMbbl)Condensate (MMbbl)

COMPANY SHARE CASHFLOW (Millio n US$/year)Year 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035+ Total

Gross Production Revenue 21.9 23.3 19.7 12.2 6.0 3.9 - - - - - - - - - - - - - - - 87.09Effective Royalty 5.3 5.4 4.1 2.3 1.0 0.7 - - - - - - - - - - - - - - - 18.84Net Production Revenue 16.6 17.9 15.6 10.0 4.9 3.2 - - - - - - - - - - - - - - - 68.25Other Income - - - - - - - - - - - - - - - - - - - - - -Oper. Costs + G&A, Local Taxes 3.8 3.8 3.9 4.5 4.6 4.3 - - - - - - - - - - - - - - - 24.91Abandonment Costs - - - - - 4.6 - - - - - - - - - - - - - - - 4.58

Op. Cash Inc. Before Tax 12.9 14.1 11.7 5.4 0.3 (5.6) - - - - - - - - - - - - - - - 38.76Capital - - - - - - - - - - - - - - - - - - - - - -TPDC Past Capital Repayment 16.1 12.0 5.0 1.8 - - - - - - - - - - - - - - - - - 34.83Cash Flow Before Tax 28.9 26.1 16.7 7.2 0.3 (5.6) - - - - - - - - - - - - - - - 73.59Income Tax - - 0.4 0.4 0.1 - - - - - - - - - - - - - - - - 0.90Cash Flow After Tax 28.9 26.1 16.3 6.8 0.2 (5.6) - - - - - - - - - - - - - - - 72.69

2014-12-31

Total CompanyField Share

Table 5.11 Cash Flow Summary Proved Developed + Undeveloped (Wentworth)




y p p ( )SUMMARY OF OIL AND GAS FIELD RESERVES, PRODUCTION AND CASHFLOW Production Forecast:

Total ProvedCOMPANY: Wentworth Resources Reserves Level: Total Proved RPS Forecast 2015-01-01





Crude Oil (MMstb) - - - - Gross Revenue 303.0 242.8 199.6 167.6 143.3 Cost (Million US$): 5.46Sales Gas (BCF) 279.2 244.3 89.2 68.2 Net Revenue 231.6 186.3 153.6 129.2 110.7 Year: 2026NGL (MMbbl) - - - - Operating Costs 57.0 42.3 32.7 26.1 21.5Condensate (MMbbl) - - - - Capital Costs 28.1 26.1 24.3 22.8 21.5







Crude Oil (MMstb)Sales Gas (BCF) 7.12 9.44 9.44 14.91 13.69 10.48 7.87 5.86 4.29 3.06 2.02 1.00 - - - - - - - - - -NGL (MMbbl)Condensate (MMbbl)


Gross Production Revenue 22.4 30.1 30.7 49.1 46.0 36.0 27.7 21.1 15.9 11.7 8.0 4.2 - - - - - - - - - 303.02Effective Royalty 5.4 7.1 6.5 10.0 9.0 6.8 6.3 8.9 5.8 3.3 1.4 0.7 - - - - - - - - - 71.43Net Production Revenue 17.0 23.0 24.2 39.1 37.0 29.2 21.4 12.2 10.1 8.4 6.5 3.5 - - - - - - - - - 231.59Other Income - - - - - - - - - - - - - - - - - - - - - -Oper. Costs + G&A, Local Taxes 3.8 4.0 4.0 4.7 4.8 4.8 4.9 5.0 5.1 5.2 5.4 5.5 - - - - - - - - - 57.20Abandonment Costs - - - - - - - - - - - 5.5 - - - - - - - - - 5.46

Op. Cash Inc. Before Tax 13.3 19.0 20.2 34.4 32.2 24.4 16.4 7.2 4.9 3.1 1.2 (7.5) - - - - - - - - - 168.94Capital 12.8 4.5 6.8 4.1 - - - - - - - - - - - - - - - - - 28.13TPDC Past Capital Repayment 8.5 17.7 6.6 2.2 - - - - - - - - - - - - - - - - - 35.04Cash Flow Before Tax 9.0 32.3 20.0 32.6 32.2 24.4 16.4 7.2 4.9 3.1 1.2 (7.5) - - - - - - - - - 175.85Income Tax - - 0.8 1.9 2.1 1.8 1.3 0.7 0.5 0.3 0.2 - - - - - - - - - - 9.62Cash Flow After Tax 9.0 32.3 19.2 30.7 30.2 22.6 15.1 6.4 4.4 2.8 1.0 (7.5) - - - - - - - - - 166.23

2014-12-31


Table 5.12 Cash Flow Summary Proved + Probable (Wentworth)




y ( )SUMMARY OF OIL AND GAS FIELD RESERVES, PRODUCTION AND CASHFLOW Production Forecast:

Total Proved + ProbableCOMPANY: Wentworth Resources Reserves Level: Total Proved + Probable RPS Forecast 2015-01-01












Crude Oil (MMstb)Sales Gas (BCF) 7.12 15.09 13.50 14.93 14.85 13.85 11.62 9.80 8.25 6.95 5.80 4.84 4.03 3.32 2.68 2.07 1.55 1.22 - - - -NGL (MMbbl)Condensate (MMbbl)


Gross Production Revenue 22.4 47.8 43.7 49.2 49.9 47.5 40.7 35.0 30.1 25.9 22.1 18.9 16.1 13.5 11.2 8.9 6.8 5.5 - - - 495.31Effective Royalty 5.4 10.0 8.7 9.7 9.8 19.7 20.7 17.3 14.3 11.8 9.5 7.5 5.8 4.2 2.7 1.7 1.3 1.0 - - - 161.12Net Production Revenue 17.0 37.8 35.0 39.4 40.1 27.8 19.9 17.7 15.8 14.2 12.7 11.4 10.3 9.3 8.5 7.2 5.6 4.5 - - - 334.20Other Income - - - - - - - - - - - - - - - - - - - - - -Oper. Costs + G&A, Local Taxes 3.8 4.0 4.0 4.7 4.8 4.8 4.9 5.0 5.1 5.2 5.4 5.5 5.6 5.7 5.8 5.9 5.3 5.4 - - - 90.89Abandonment Costs - - - - - - - - - - - - - - - - - 6.1 - - - 6.15

Op. Cash Inc. Before Tax 13.3 33.8 31.0 34.8 35.4 22.9 15.0 12.7 10.7 8.9 7.3 6.0 4.8 3.7 2.7 1.3 0.2 (7.1) - - - 237.16Capital 12.8 2.7 10.0 4.3 0.1 - - - - - - - - - - - - - - - - 29.86TPDC Past Capital Repayment 8.5 21.2 5.2 - - - - - - - - - - - - - - - - - - 34.92Cash Flow Before Tax 9.0 52.3 26.1 30.5 35.3 22.9 15.0 12.7 10.7 8.9 7.3 6.0 4.8 3.7 2.7 1.3 0.2 (7.1) - - - 242.22Income Tax - 1.5 1.8 2.2 2.3 1.8 1.2 1.0 0.9 0.8 0.6 0.5 0.4 0.3 0.2 0.1 0.1 - - - - 15.90Cash Flow After Tax 9.0 50.8 24.3 28.4 33.0 21.1 13.8 11.6 9.8 8.1 6.7 5.4 4.3 3.3 2.4 1.2 0.2 (7.1) - - - 226.33

2014-12-31


Table 5.13 Cash Flow Summary Proved + Probable + Possibl e (Wentwor th)




SUMMARY OF OIL AND GAS FIELD RESERVES, PRODUCTION AND CASHFLOW Production Forecast:Total Proved + Probable + Possible

COMPANY: Wentworth Resources Reserves Level: Total Proved + Probable + Possible RPS Forecast 2015-01-01OPERATOR: Maurel et Prom Price Forecast Case: RPS Forecast 2015-01-01

FIELD: Mnazi Bay Average Annual Cost Inflati on: 2.00%COMPANY SHARE: 31.94% Effective Date:










Crude Oil (MMstb)Sales Gas (BCF) 7.12 15.17 14.74 14.92 14.91 14.81 14.85 14.72 14.31 13.26 13.39 13.46 13.93 10.92 8.55 6.88 5.57 4.53 3.66 2.96 2.35 1.55NGL (MMbbl)Condensate (MMbbl)


Gross Production Revenue 22.4 48.1 47.6 49.2 50.1 50.7 51.9 52.4 51.9 49.1 50.5 51.8 54.6 43.8 35.0 28.8 23.8 19.8 16.3 13.5 18.4 829.57Effective Royalty 5.4 10.2 9.6 9.8 9.9 17.1 27.3 27.7 27.4 25.5 26.3 27.0 28.7 22.0 16.8 13.0 10.0 7.6 5.5 3.7 3.6 334.10Net Production Revenue 17.0 37.9 38.0 39.4 40.1 33.7 24.5 24.8 24.6 23.6 24.2 24.8 26.0 21.7 18.2 15.8 13.8 12.2 10.8 9.7 14.7 495.46Other Income - - - - - - - - - - - - - - - - - - - - - -Oper. Costs + G&A, Local Taxes 3.8 4.0 4.0 4.7 4.8 4.8 4.9 5.2 5.1 5.2 5.4 5.5 5.6 5.7 5.8 5.9 6.0 6.1 6.3 6.4 13.2 118.27Abandonment Costs - - - - - - - - - - - - - - - - - - - - 10.0 10.05Op. Cash Inc. Before Tax 13.3 33.9 34.0 34.7 35.4 28.8 19.6 19.6 19.4 18.3 18.8 19.3 20.4 16.1 12.5 9.8 7.8 6.0 4.6 3.4 (8.5) 367.15Capital 12.8 12.4 6.6 4.1 3.6 0.1 0.1 - - - - - - - - - - - - - - 39.79TPDC Past Capital Repayment 8.5 19.5 7.0 - - - - - - - - - - - - - - - - - - 34.96Cash Flow Before Tax 9.0 41.0 34.3 30.6 31.8 28.7 19.4 19.6 19.4 18.3 18.8 19.3 20.4 16.1 12.5 9.8 7.8 6.0 4.6 3.4 (8.5) 362.31Income Tax - 1.4 1.9 2.1 2.2 2.0 1.5 1.5 1.5 1.5 1.5 1.5 1.6 1.4 1.1 0.9 0.7 0.5 0.4 0.3 0.2 25.82Cash Flow After Tax 9.0 39.6 32.4 28.5 29.6 26.7 17.9 18.1 17.9 16.8 17.3 17.8 18.8 14.7 11.3 9.0 7.1 5.5 4.2 3.0 (8.7) 336.50

2014-12-31


RPS Mna i Ba Reser es Assessment as at December 31 2014




6.0 REFERENCES

1 Petroleum Resource Management System (SPE – PRMS)”, 2007.

2 USGS 2012. Assessment of Undiscovered Oil and Gas Resources of Four East Africa GeologicProvinces. Fact Sheet 2012-3039

3 Artumas Group Inc. Petrophysical Analysis on Offshore Tanzania Mnazi Bay Bay #1, 10° 19’ 45.5”S 40°23’ 27”E”, Al Lye & Associates Inc., January 2004.

4 “Artumas Group Inc., Petrophysical Analysis on Offshore Tanzania Mnazi Bay Bay #2_ST2,Y=8,858,584 X=654,326” Al Lye & Associates Inc., September 2006.

5 “Artumas Group Inc., Petrophysical Analysis on Offshore Tanzania Mnazi Bay Bay #3, X=8,858,424Y=6,545,622”, Al Lye & Associates Inc., January 2007.

6 “Artumas Group Inc., Petrophysical Analysis on Offshore Tanzania; Mnazi Bay Bay Wells MB-1, MB-2,MB-3, MS-1X”, Al Lye & Associates Inc., July 2007.

7 “Compositional Analysis Study for Artumas Energy Mnazi Bay Bay (Well MB-2) RFL20070004 FinalReport”, Core Laboratories International B.V., Abu Dhabi Branch, January 30, 2007.

8 “Compositional Analysis Study for Artumas Energy Mnazi Bay Bay MS-1X, DST-1, RFL20070041 FinalReport”, Core Laboratories International B.V., Abu Dhabi Branch, March 14, 2007.

9 “Compositional Analysis Study for Artumas Energy, AG1 Minazibay (Sic) Project RFL20070064 FinalReport”, (Wells MS-1X and MB-3) Core Laboratories International B.V., Abu Dhabi Branch, May 7, 2007.

10 “C iti l A l i St d f A t E g AG1 Mi ib (Si ) P j t RFL20070064 Fi l

RPS Mnazi Bay Reserves Assessment as at December 31 2014




APPENDIX 1.0 GLOSSARY OF TECHNICAL TERMS



A1.0 GLOSSARY OF TERMS AND ABBREVIATIONS

AOF Absolute Open Flow API Oil gravity in American Petroleum Institute (API) units

AVO Amplitude vs OffsetB Billion (10 9)bbl BarrelsBscf billions of standard cubic feetboe barrels of oil equivalentbopd barrels of oil per daybpd barrels per dayCPF Central Processing FacilityCPI Computer-Processed Interpretation

d DayDST Drill Stem TestE Gas Expansion Factor (surface volume / reservoir volume)EUR Estimated Ultimate RecoveryEWT Extended Well Testft feetFWL Free Water LevelGDT Gas-Down-ToGIIP Gas Initially-In-Place

GOC Gas-Oil-ContactGOR Gas/Oil RatioGRV Gross Rock VolumeGSA Gas Sales AgreementGWC Gas-Water ContactIPR Inflow performance relationship1P Proved2P Proved + Probable3P Proved + Probable + Possible



M Thousand (only used with Imperial oilfield units)mD Permeability in millidarciesmKB measured well depth in metres, referenced to drilling rig kelly bushing.MDT® Shlumberger’s wireline formation sampling tool M Thousand (only used with Imperial oilfield units)Mscf thousands of standard cubic feet

Mscf/d Thousands of standard cubic feet per dayMM Million (only used with Imperial oilfield units)MMscf millions of standard cubic feetMMscf/d millions of standard cubic feet per dayMMbbl millions of barrelsMMboe millions of barrels of oil equivalentMMstb Millions of stock tank barrelsN/G Net-to-Gross RatioNPV Net Present Value (at a specified discount rate and specified discount date)P 10 10% Statistical Confidence Level of Value referencedP 50 50% Statistical Confidence Level of Value referenced

P 90 90% Statistical Confidence Level of Value referencedPVT Pressure-Volume-Temperature (Fluid properties)RF Recovery FactorRFT Repeat Formation Tester (wireline pressure measurement and sampling tool)scf standard cubic feetscf/d standard cubic feet per day

stb/d stock tank barrels per daySS SubseaS w Water SaturationTVDSS True Vertical Depth SubseaTWT Two-way TimeUR Ultimate RecoveryZ Gas deviation or ‘supercompressibility’ factor

RPS Mnazi Bay Reserves Assessment as at December 31 2014




APPENDIX 2.0 MNAZI BAY/MSIMB ATI STRUCTURE AND ISOPACH MAPS

RPS Energy Mnazi Bay Field Reserves Assessment



ECV 2129 February 2015

APPENDIX 2: UPPER K SANDS DEPTH MAP





APPENDIX 2: UPPER K SANDS GROSS ROCK VOLUME ABOVE GAS-WATER CONTACT (1593M)





APPENDIX 2: UPPER K SANDS P10, P50 & P90 AREAS

P90

P50

P10





APPENDIX 2: LOWER K SANDS DEPTH MAP





APPENDIX 2: LOWER K SANDS GROSS ROCK VOLUME ABOVE GAS-WATER CONTACT (1633M)





APPENDIX 2: MB UPPER SANDS DEPTH MAP





APPENDIX 2: MB UPPER SANDS GROSS ROCK VOLUME AB OVE GAS-WATER CONTACT (1864M)





APPENDIX 2: MB UPPER SANDS P10, P50 & P90 AREAS

P10

P50

P90





APPENDIX 2: MB LOWER SANDS DEPTH MAP





APPENDIX 2: MB LOWER SANDS GROSS ROCK VOLUME ABOVE GAS-WATER CONTACT (1905M)




APPENDIX 2: MB LOWER SANDS P10, P50 & P90 AREAS

P90P50

P10

Documents

RPS March 2 2014 Reserves FINAL