EVALUATION OF HERITAGE OIL PLc’s PETROLEUM … · RPS Energy Heritage – CPR RPS has assessed...

The Directors Heritage Oil Plc Ordnance House 31 Pier Road St Helier Jersey, JE4 8PW Channel Islands J.P. Morgan Cazenove Limited 125 London Wall London EC2Y 5AJ Shoreline Natural Resources Limited Shoreline House 46 Industrial Avenue Ilupeju Lagos Nigeria Standard Bank 20 Gresham Street London EC2V 7JE

Project Ref: ECV1851 18th July 2012

Gentlemen,

EVALUATION OF HERITAGE OIL PLc’s PETROLEUM ASSETS In response to your request, and the subsequent Letter of Engagement dated 10th May 2012, RPS Energy Consultants Limited (“RPS”) has completed an independent evaluation of certain oil and gas properties in Nigeria, Russia and Kurdistan in which Heritage Oil Plc (“Heritage”) has an interest (”the Properties”). This report is issued by RPS under the appointment by Heritage Oil Plc and is produced as part of the work detailed therein and is subject to the terms and conditions of the Letter of Engagement made on 10th May 2012. This report fulfils the requirements of the “Prospectus Rules” published by the UK Financial Services Authority from time to time and governed by the UK Listing Authority, the “Prospectus Directive” (2003/71/EC) and the Prospectus Regulations (809/2004), “CESR’s recommendations for the consistent implementation of the European Commission’s Regulation on Prospectuses No. 809/2004” (January 2005), including the European Securities and Markets Authority’s amendments to such recommendations in document ESMA/2011/81. This report has been prepared for inclusion by Heritage in a prospectus or circular in connection with a Reverse Takeover, Class 1 Transaction, RPS has estimated a range of reserves and resources as at 31st March 2012, based on data and information available up to that date. In estimating resources RPS has used standard petroleum engineering techniques, which combine geological and production data with information concerning fluid characteristics and reservoir pressure, where available. RPS has estimated the degree of uncertainty inherent in the

RPS Energy Heritage – CPR

measurements and interpretation of the data and has calculated a range of reserves and resources and risk factors in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (See Section 2.2). The data set supplied by Heritage included geological, geophysical and engineering data, together with reports and presentations pertaining to the contractual and fiscal terms applicable to the assets. In carrying out this review RPS has relied solely upon this information. RPS prepared a Competent Person’s Report for Heritage in early 2008 and again in late 2009. The initial report, dated 28th March 2008, formed part of the prospectus for Heritage’s listing on the London Stock Exchange. The second report, dated 18th December 2009, formed part of the prospectus in connection with the disposal of Heritage’s Ugandan assets Summary of Reserves and Resources Reserves The gross reserves and the net reserves attributable to Heritage are given in Table 1 and Table 2.

Gross Remaining Reserves

Heritage Net Working Interest2 Reserves

Heritage Net Entitlement Reserves at

Base Case Price Forecast,

Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

(MMstb) (MMstb) (MMstb) (MMstb) (MMstb) (MMstb) Proved Reserves (1P) 538 430 225 180 240 192

Proved plus Probable Reserves (2P) 1,114 891 456 365 495 396

Proved plus Probable plus Possible Reserves (3P) 1,733 1,387 709 567 770 616

Notes 1. Values net of royalty are the most economically meaningful, as they reflect the deduction of royalty volumes to which the Government is entitled. Values gross of royalty are shown at Heritage's request.

2. Net Working Interest volumes are notional values resulting from the dynamics of changing Net Profit Interests, as detailed in section 6.3.1of this report. Net Entitlement volumes are more economically meaningful as they represent the actual volumes to which Heritage is entitled.

3. Heritage has informed us it is purchasing a 45% interest in OML 30 using Shoreline Natural Resources Limited (hereafter “SNRL”), which consists of Heritage and a local partner, Shoreline Power (hereafter “Shoreline”). To the end of 2012, Shoreline can elect to acquire an additional 30% interest in SNRL, which if exercised in full would reduce Heritage’s Net Interest by 30%, in which case Heritage’s Net Interest would be 70% of that calculated in this table.

Table 1: Summary of Reserves for OML 30 as of 31st March 2012




Base Case Price Forecast

Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

(MMstb) (MMstb) (MMstb) (MMstb) (MMstb) (MMstb) Proved Reserves (1P) 24 24 23 23 23 23 Proved plus Probable Reserves (2P) 69 69 65 65 65 65

Proved plus Probable plus Possible Reserves (3P) 172 172 163 163 163 163

Notes 1. The Chumpasskoye fiscal regime does not include a royalty. 2. Under the terms of the Chumpasskoye licence the Net Working Interest volumes and Net Entitlement

volumes are the same.

Table 2: Summary of Reserves for Zapadno Chumpasskoye Field as of 31st March 2012


RPS has assessed the reserves in OML30 based on Heritage’s field development plan for the developed reservoirs and selected undeveloped reservoirs. It is noted that there are many undeveloped reservoirs which have not been assessed. There may be additional reserves in the remaining undeveloped reservoirs and behind pipe in some of the developed reservoirs that have not currently been targeted with new wells. These additional resources could represent a significant upside on reserves but have not been quantified. The licence is due to expire in 2019. However, we assume, based on our general experience in licence valuations, that the government will renew the licence. In our assessment the licence expiry date is assumed to equal either the economic limit or 2049 whichever is the sooner for each case considered. Resources A summary of the gross Contingent Resources, excluding inerts, and the net working interest Contingent Resources in Heritage’s Properties is given in Tables 3 to 5.

Gross Field Heritage Net WI Heritage Net Entitlement

Volumes Gross of Royalty

Net of Royalty 1

Gross of Royalty 2,3

Net of Royalty 1,2,3 Net of Royalty

(MMstb) (MMstb) (MMstb) (MMstb) (MMstb) 1C Resources 37 33 21 19 8.3 2C Resources 83 75 47 42 15 3C Resources 167 150 94 84 25 Mean Resources4 94 85 53 48 16 Notes 1. Values net of royalty are the most economically meaningful, as they reflect the deduction of royalty

volumes to which the Government is entitled. Values gross of royalty are shown at Heritage's request. 2. Net Working Interest volumes are notional values obtained by multiplying the corresponding Gross

Field values by Heritage's working interest. They are not economically meaningful, however, as they do not reflect Heritage's actual entitlement under the terms of the Miran PSC. Net Entitlement volumes are economically meaningful as they do represent the actual volumes to which Heritage is entitled. They are by definition net of royalty.

3. Calculated assuming state back-in upon commerciality which reduces Heritage net working interest from 75% to 56.25%.

4. Mean values are estimated using a probability-weighted average calculation, in which the probabilities are 30%, 40% and 30% for the IC, 2C and 3C resources, respectively.

Table 3: Summary of Oil and Condensate Contingent Resources for Miran Field as of 31st March 2012

Gross Field Heritage Net WI Heritage

Net Entitlement


Net of Royalty 1


Net of Royalty 1,2,3

Net of Royalty

(Bscf) (Bscf) (Bscf) (Bscf) (Bscf)

1C Resources 1,760 1,584 990 891 491 2C Resources 2,929 2,637 1,648 1,483 669 3C Resources 5,087 4,578 2,861 2,575 940 Mean Resources4 3,226 2,903 1,815 1,633 697 Notes 1. Values net of royalty are the most economically meaningful, as they reflect the deduction of royalty

volumes to which the Government is entitled. Values gross of royalty are shown at Heritage's request. 2. Net Working Interest volumes are notional values obtained by multiplying the corresponding Gross Field

values by Heritage's working interest. They are not economically meaningful, however, as they do not reflect Heritage's actual entitlement under the terms of the Miran PSC. Net Entitlement volumes are economically meaningful as they do represent the actual volumes to which Heritage is entitled. They are by definition net of royalty.



Table 4: Summary of Gas Contingent Resources for Miran Field as of 31st March 2012



Net Entitlement


Net of Royalty 1



Net of Royalty

(MMboe) (MMboe) (MMboe) (MMboe) (MMboe)

1C Resources 340 306 191 172 93

2C Resources 588 529 331 298 130

3C Resources 1,044 939 587 528 187

Mean Resources4 650 585 366 329 136 Notes 1. Values net of royalty are the most economically meaningful, as they reflect the deduction of royalty





Table 5: Summary of Oil, Gas and Condensate Contingent Resources for Miran Field as of 31st March 2012

A summary of the gross Prospective Resources and Heritage’s equity interest Prospective Resources1 in Miran that have been reviewed by RPS is given in Table 6 along with the RPS estimate of Geological Probability of Success (GPoS). These volumes have been stochastically consolidated for Miran East, Miran West and Miran South to provide a basis for valuing a light oil development.

1 In the event of discovery and development Heritage net entitlement resources will be a function of the contract terms and will be less than the net working interest resources.


Gross Estimate Heritage Working Interest Share 1 GPoS2

(%) Low (P90)

Best(P50)

High(P10) Mean Low

(P90) Best(P50)

High (P10) Mean

Resources (MMstb)

Miran East Oil (MMstb) 11 44 169 74 6 25 95 42 58%

Miran West Oil (MMstb) 17 56 131 67 10 32 74 38 38%

Miran South Oil (MMstb) 4 17 64 28 2 10 36 16 14%

Non-Associated Gas (Bscf)

Miran East Gas (Bscf) 78 212 499 256 44 119 281 144 71%

Miran West Gas (Bscf) 21 94 268 124 12 53 151 70 58%

Miran South Gas (Bscf) 15 61 155 75 8 34 87 42 28%

Condensate (MMstb)

Miran East (MMstb) 0.6 2.0 5.3 2.6 0.3 1.1 3.0 1.5 71%

Miran West (MMstb) 0.2 1.3 4.4 1.9 0.1 0.7 2.5 1.1 58%

Miran South (MMstb) 0.1 0.6 1.7 0.8 0.1 0.3 1.0 0.5 28%

Notes 1. Calculated assuming state back-in upon commerciality which reduces Heritage net working interest from 75% to

56.25%. 2. The chance or probability of discovering hydrocarbon volumes within the range defined. This is not an estimation

of commercial chance of success.

Table 6: Summary of Prospective Resources for Miran

Valuation An economic valuation of reserves has been undertaken. Value is linked to a long term price forecast for Brent. The RPS Base Case price, used for all valuations presented in this report, is given in Table 7. Appropriate differentials have been applied to the different assets.

Base Price Case (US$/stb, MOD)

2012 (9 months) 120.00 2013 112.50 2014 105.30 2015 100.81 2016 102.83 2017 104.89 2018 106.99 2019 109.13 2020 111.31 2021 113.53 2022 115.80 2023 118.12 2024 120.48

2025 onwards + 2% p.a.

Table 7: RPS Price Base Case Forecasts (US$/stb Money of the Day)


Reserves The post-tax Net Present Values (NPV) of Heritage’s Reserves in OML30 and Zapadno Chumpasskoye at various discount rates, applying the RPS Base Case price forecasts, are tabulated in Table 8a, and Table 9. Table 8b shows an alternative valuation for OML30 with a different Income Tax scenario based on Heritage’s view of pending legislation.

Economic

Limit Post-Tax Net Present Value

(US$ Million, Money of the Day)

0% 5.0% 7.5% 10.0% 15.0%

Proved Reserves (1P) 2046 3,191 2,265 1,950 1,699 1,328

Proved plus Probable Reserves (2P) 2049 6,754 4,372 3,643 3,089 2,313

Proved plus Probable plus Possible Reserves (3P) 2049 10,770 6,563 5,358 4,470 3,270

Table 8a: Post-Tax Valuation (Net Heritage Share) of Heritage’s Reserves for OML30 as of 31st March 2012

Economic



0% 5.0% 7.5% 10.0% 15.0%




Table 8b: Post-Tax Valuation (Net Heritage Share) of Heritage’s Reserves for OML30 as of 31st March 2012, Heritage alternative Income Tax Scenario

Economic



0% 5.0% 7.5% 10.0% 15.0%

Proved Reserves (1P) 2032 192 109 78 52 15

Proved plus Probable Reserves (2P) 2036 887 546 429 336 206

Proved plus Probable plus Possible Reserves (3P) 2036 2,912 1,630 1,253 976 610

Table 9: Post-Tax Valuation (Net Heritage Share) of Heritage’s Reserves for Zapadno Chumpasskoye Field as of 31st March 2012

Qualifications RPS is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, RPS does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this report. Mr Gordon Taylor, Technical Director, for RPS Energy, has supervised the evaluation. Mr Taylor is a Chartered Engineer and Chartered Geologist. Mr. Taylor has over 30 years exploration and production experience. He is a Chartered Geologist and Chartered Engineer in UK. Other RPS Energy employees involved in this work hold at least a Masters degree in geology, geophysics, petroleum engineering or a related subject or have at least five years of relevant experience in the practice of geology, geophysics or petroleum engineering


Basis of Opinion The evaluation presented herein reflects our informed judgement based on accepted standards of professional investigation, but is subject to generally recognised uncertainties associated with the interpretation of geological, geophysical and engineering data. The evaluation has been conducted within our understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. However, RPS is not in a position to attest to the property title, financial interest relationships or encumbrances related to the properties. RPS has taken the working interest that Heritage has in the Properties, as presented by Heritage, and RPS has not investigated nor do we make any warranty as to Heritage's interest in the Properties. As of the date this report was issued, RPS has not seen a signed Sales and Purchase Agreement for the Nigerian licence although Heritage has informed RPS that the SPA was signed by Heritage Oil Plc and Shoreline Power, Joint Venture Partners in Shoreline Natural Resources Limited, on 29 June 2012. RPS has also not seen documentary evidence of any commitment to the expenditure to develop this licence. RPS has been advised that full government approval for the development in Nigeria is expected in August 2012. Our estimates of reserves and resources and value are based on the data set available to, and provided by, Heritage. RPS has accepted, without independent verification, the accuracy and completeness of these data. No site visits have been undertaken. The report represents RPS’ best professional judgement and should not be considered a guarantee or prediction of results. It should be understood that any evaluation, particularly one involving exploration and future petroleum developments, may be subject to significant variations over short periods of time as new information becomes available. As agreed in the Letter of Engagement, RPS cannot and does not guarantee the accuracy or correctness of any interpretation made by it. In particular, RPS does not warrant that the work will be any form of guarantee of geological or commercial outcome. This report relates specifically and solely to the subject assets and is conditional upon various assumptions that are described herein. The report, of which this letter forms part, must therefore be read in its entirety. Except with permission from RPS, this report may not be reproduced or redistributed, in whole or in part, to any other person or published, in whole or in part, for any purpose without the express written consent of RPS. However in instances where excerpts only are to be reproduced or published, this cannot be done without the express permission of RPS. The report was provided for the sole use of Heritage and its advisors on a fee basis. RPS has given and not withdrawn its written consent to the issue of the prospectus, with its name included within it, and to the inclusion of this report and references to this report in the prospectus. For the purposes if Prospectus Rule 5.5.3R(2)(f) RPS accepts responsibility for the information contained in the RPS report set out in this part of the prospectus and those parts of the prospectus which include references to this report and declares that to the best knowledge and belief of RPS, having taken all reasonable care to ensure that such is the case, the information contained herein is in accordance with the facts and does not omit anything likely to affect the import of such information. Yours faithfully, RPS Energy Consultants Ltd

Gordon Taylor, C.Eng, C. Geol Director, Subsurface


ECV 1851 i July 2012

Table of Contents

1. Description of Assets ............................................................................................... 1 1.1 Liabilities ....................................................................................................................... 3

2. Methods Used in this Report ................................................................................... 4 2.1 General ......................................................................................................................... 4

2.2 Reserves and Resource Classification ......................................................................... 4

2.3 Risk Assessment ........................................................................................................... 4

2.3.1 Contingent Resources ..................................................................................... 4

2.3.2 Prospective Resources (Exploration Prospects) ............................................. 4

2.4 Uncertainty Estimation .................................................................................................. 5

3. OML30 ........................................................................................................................ 6 3.1 Data Available ............................................................................................................... 6

3.2 Field Overviews ............................................................................................................. 8

3.2.1 Afiesere ............................................................................................................ 8

3.2.2 Eriemu .............................................................................................................. 8

3.2.3 Evwreni ............................................................................................................ 8

3.2.4 Oweh ................................................................................................................ 8

3.2.5 Olomoro-Oleh ................................................................................................... 8

3.2.6 Kokori ............................................................................................................... 9

3.2.7 Oroni ................................................................................................................ 9

3.2.8 Uzere-West ...................................................................................................... 9

3.3 In-place Volumes .......................................................................................................... 9

3.4 Assessment of Resources .......................................................................................... 10

3.4.1 Rationale for Subdivision ............................................................................... 11

3.4.2 Decline Curve Analysis (DCA) Methodology ................................................. 11

3.4.3 Existing Producing Wells (PDP) ..................................................................... 13

3.4.4 Wells Currently Shut- in (PDNP) .................................................................... 13

3.4.5 Gas Lift Optimisation (PDP & PDNP) ............................................................ 13

3.4.6 New Wells (PUD) ........................................................................................... 13

3.4.7 Recovery Factor ............................................................................................. 14

3.5 Production Forecasts .................................................................................................. 14

3.6 Facilities and Cost Estimates ...................................................................................... 23

3.6.1 Capital Expenditure ........................................................................................ 23

3.6.2 Drilling Costs .................................................................................................. 24

3.6.3 Operating Costs ............................................................................................. 24

3.6.4 Abandonment Costs ...................................................................................... 24

4. Zapadno Chumpasskoye ........................................................................................ 25 4.1 Data Available ............................................................................................................. 25

4.2 Geology ....................................................................................................................... 25

4.2.1 Regional Setting ............................................................................................. 25


ECV 1851 ii July 2012

4.2.2 Zapadno Chumpasskoye Field ...................................................................... 25

4.2.3 Petrophysics ................................................................................................... 26

4.2.4 In-place Volumes ........................................................................................... 28

4.3 Petroleum Engineering ............................................................................................... 28

4.3.1 Reservoir Fluid Properties ............................................................................. 28

4.3.2 Well Performance & Deliverability .................................................................. 28

4.3.3 Development Plan (Subsurface) .................................................................... 29

4.3.4 Recovery Mechanisms ................................................................................... 31

4.3.5 Production Profiles ......................................................................................... 31

4.3.6 Developmental Risk ....................................................................................... 33


4.4.1 Capital Expenditure ........................................................................................ 34

4.4.2 Drilling Costs .................................................................................................. 34

4.4.3 Operating Costs ............................................................................................. 35

4.4.4 Abandonment Costs ...................................................................................... 35

5. KURDISTAN – MIRAN BLOCK ............................................................................... 36 5.1 Available Data ............................................................................................................. 36

5.2 Wells on the Miran Structure ....................................................................................... 37

5.2.1 Miran West-1 (M1) ......................................................................................... 37

5.2.2 Miran West-2 (M2) ......................................................................................... 38

5.2.3 Miran West-3 (M3) ......................................................................................... 38

5.2.4 Miran-4 (M4, Miran East-1) ............................................................................ 38

5.3 Structural Interpretation .............................................................................................. 38

5.4 Well Tests ................................................................................................................... 40

5.4.1 Miran West-1 Drill Stem Tests ....................................................................... 40



5.4.4 Contacts – Miran West ................................................................................... 43

5.5 In-place Volumes ........................................................................................................ 43

5.6 Reservoir Engineering ................................................................................................ 46

5.6.1 Zone 4 Oil Recovery Factors and Resources ................................................ 47

5.6.2 Zone 4 Oil in Miran East ................................................................................ 49

5.6.3 Zone 4 Oil in Miran South .............................................................................. 51

5.6.4 Tanjero Oil ...................................................................................................... 53

5.6.5 Zone 2a, 2b and 3 Consolidated Gas in Miran West ..................................... 55

5.6.6 Triassic Gas in Miran West ............................................................................ 57

5.6.7 Zone 2a, 2b and 3 Consolidated Gas in Miran East ...................................... 59

5.6.8 Zone 2a, 2b and 3 Consolidated Gas in Miran South .................................... 61


5.7.1 Contingent Resources – Miran West ............................................................. 63

5.7.2 Prospective Resources .................................................................................. 64


ECV 1851 iii July 2012

6. Economics ............................................................................................................... 65 6.1 Valuation Assumptions ............................................................................................... 65

6.1.1 General .......................................................................................................... 65

6.1.2 Oil Prices ........................................................................................................ 65

6.2 Valuation Methodology ............................................................................................... 66

6.2.1 Reserves ........................................................................................................ 66

6.2.2 Contingent and Prospective Resources ........................................................ 67

6.3 NIGERIA – OML30 ...................................................................................................... 67

6.3.1 Fiscal Regime and Contract Terms ............................................................... 67

6.3.2 Price Assumptions ......................................................................................... 69

6.3.3 Economic Limit ............................................................................................... 70

6.3.4 Valuation Summary ........................................................................................ 70

6.3.5 Sensitivity to Oil Price .................................................................................... 72

6.4 Russia – Zapadno Chumpasskoye ............................................................................. 72



6.4.3 Transportation Costs ...................................................................................... 73

6.4.4 Exchange Rate and Tax Losses .................................................................... 74

6.4.5 Valuation Summary ........................................................................................ 74

6.4.6 Sensitivity to Oil Price .................................................................................... 74

6.5 Kurdistan – Miran Block .............................................................................................. 75



6.5.3 Sunk Costs ..................................................................................................... 75

6.5.4 Post Tax Contractor Share ............................................................................ 76

APPENDIX A: GLOSSARY OF TECHNICAL TERMS ......................................................... 78 APPENDIX B: SPE/WPC/AAPG/SPEE RESERVE/RESOURCE DEFINITIONS ................. 81 APPENDIX C: CONTRACTOR SHARE OF REVENUE AND COSTS FOR

CONTINGENT RESOURCES AND PROSPECTIVE RESOURCES ............ 85 APPENDIX D: OML 30 FORECASTS (FROM 1 APRIL 2012) OF PRODUCTION AND

CASHFLOWS ............................................................................................. 105


ECV 1851 iv July 2012

List of Figures

Figure 1-1: Nigerian Licence Location Map ..................................................................................... 1

Figure 1-2: Russian Licence Location Map ..................................................................................... 2

Figure 1-3: Kurdistan Licence Location Map ................................................................................... 2

Figure 3-1: Nigeria Delta Area ......................................................................................................... 7

Figure 3-2: Map Showing Location of OML30 Fields ...................................................................... 7

Figure 3-3: Eriemu Strike Cross-section ......................................................................................... 8

Figure 3-4: OML30 Production Data (from July 2010) .................................................................. 10

Figure 3-5: 1P Example – Water-cut versus Cumulative Oil Plot L8000X Reservoir Kokori ........ 12

Figure 3-6: 3P Example - Semi Log Water-Oil-Ratio versus Cumulative Oil Plot L8000X Reservoir Kokori .......................................................................................................... 12

Figure 3-7: Production Forecasts for Afiesere and Eriemu Combined.......................................... 15

Figure 3-8: Production Forecasts for Olomoro – Oleh .................................................................. 16

Figure 3-9: Production Forecasts for Evwreni ............................................................................... 17

Figure 3-10: Production Forecasts for Oroni ................................................................................... 18

Figure 3-11: Production Forecasts for Kokori .................................................................................. 19

Figure 3-12: Production Forecasts for Uzere-West ......................................................................... 20

Figure 3-13: Production Forecasts for Oweh .................................................................................. 21

Figure 3-14: Production Forecasts for OML30 ................................................................................ 22

Figure 4-1: Lower J1 Sand – RPS Net Pay Map (P50 Case) ....................................................... 27

Figure 4-2: Zapadno Chumpasskoye Production History (Rate versus Time) .............................. 29

Figure 4-3: Zapadno Chumpasskoye Production History (Rate versus Cumulative) .................... 29

Figure 4-4: Illustration of Inverted Nine-spot ................................................................................. 30

Figure 4-5: RPS 1P Production Profile for Zapadno Chumpasskoye ........................................... 31



Figure 4-8: Comparison of all Profiles for Zapadno Chumpasskoye ............................................. 33

Figure 5-1: Miran Block Data Base Map ....................................................................................... 37

Figure 5-2: Seismic Inline 1040 through Miran West-2 ................................................................. 39

Figure 5-3: RPS Top Zone 4 Depth Map ....................................................................................... 40

Figure 5-4: Miran West Contingent Oil Production Profiles (100% Basis) .................................... 49

Figure 5-5: Miran East Prospective Oil Production Profiles (100% Basis) .................................... 51

Figure 5-6: Miran South Prospective Oil Production Profiles (100% Basis) ................................. 53

Figure 5-7: Miran West Tanjero Prospective Oil Production Profiles (100% Basis) ..................... 55

Figure 5-8: Miran West Contingent Gas Resources Production Profiles (100% Basis) ................ 57

Figure 5-9: Miran West Prospective Gas Production Profiles (100% Basis) ................................ 58

Figure 5-10: Miran East Prospective Gas Production Profiles (100% Basis) ................................. 61

Figure 5-11: Miran South Prospective Gas Resources Production Profiles (100% Basis) ............. 62

Figure 6-1: RPS Base Forecast Price ........................................................................................... 66

Figure 6-2: Plot of Brent vs. URALS (Mediterranean) – 2010-2012 ............................................. 73


ECV 1851 v July 2012

List of Tables

Table 1-1: Summary of the Heritage Properties ............................................................................. 1

Table 3-1: Approximate Oil In-place Volumes from Shell Maps and Average Parameters ......... 10

Table 3-2: Horizontal/Vertical Well Factors for < 5 cp Reservoirs ............................................... 14

Table 3-3: Horizontal/Vertical Well Factors for > 5 cp Reservoirs ............................................... 14

Table 3-4: Maximum Recovery Factors Applied .......................................................................... 14

Table 3-5: Expected Ultimate Recovery and Remaining Technical Resources for Combined Afiesere and Eriemu Fields ....................................................................... 15

Table 3-6: Expected Ultimate Recovery and Remaining Technical Resources for Olomoro -Oleh ........................................................................................................................... 16

Table 3-7: Expected Ultimate Recovery and Remaining Technical Resources for Evwreni ....... 17

Table 3-8: Expected Ultimate Recovery and Remaining Technical Resources for Oroni ........... 18

Table 3-9: Expected Ultimate Recovery and Remaining Technical Resources for Kokori .......... 19

Table 3-10: Expected Ultimate Recovery and Remaining Technical Resources for Uzere-West ............................................................................................................................ 20

Table 3-11: Expected Ultimate Recovery and Remaining Technical Resources for Oweh ........... 21

Table 3-12: Expected Ultimate Recovery and Remaining Technical Resources for OML30 ........ 22

Table 3-13 Nigeria OML30 Facility Costs (US$MM) ..................................................................... 23

Table 4-1: Lower J1 Sand Input Parameters ............................................................................... 28

Table 4-2: Zapadno Chumpasskoye, Lower J1 Sand, STOIIP Estimates (MMstb) ..................... 28

Table 4-3: Summary of Results for Zapadno Chumpasskoye ..................................................... 33

Table 4-4: Zapadno Chumpasskoye Facility Costs (US$MM) ..................................................... 34

Table 4-5: Well Count and Well Costs ......................................................................................... 35

Table 5-1: DSTs in Miran West-1 ................................................................................................. 41



Table 5-4: Miran West - Hydrocarbons In-place and Resources (RPS) ...................................... 45

Table 5-5: Miran East - Hydrocarbons in-place and Prospective Resources (RPS) ................... 45

Table 5-6: Miran South - Hydrocarbons In-place and Prospective Resources (RPS) ................. 46

Table 5-7: Summary of Contingent Resources (RPS) ................................................................. 46

Table 5-8: Summary of Prospective Resources (RPS) ................................................................ 46

Table 5-9: Miran West Contingent Oil Production Profiles (100% Basis) .................................... 48

Table 5-10: Production Assumptions for Zone 4 Miran West Oil ................................................... 48

Table 5-11: Miran East Prospective Oil Production Profiles (100% Basis) .................................... 50

Table 5-12: Production Assumptions for Zone 4 Miran East Oil .................................................... 50

Table 5-13: Miran South Prospective Oil Production Profiles (100% Basis) ................................. 52

Table 5-14: Production Assumptions for Zone 4 Miran South Oil .................................................. 52

Table 5-15: Miran West Tanjero Prospective Oil Production Profiles (100% Basis) ..................... 54

Table 5-16: Production Assumptions for Miran West Tanjero ....................................................... 54

Table 5-17: Miran West Contingent Gas Production Profiles (100% Basis) .................................. 56


ECV 1851 vi July 2012

Table 5-18: Miran West Prospective Gas Production Profiles (100% Basis) ................................ 58

Table 5-19: Miran East Prospective Gas Production Profiles (100% Basis) ................................. 60

Table 5-20: Miran South Prospective Gas Resources Production Profiles (100% Basis) ............. 62

Table 6-1: RPS Forecast Price Cases ......................................................................................... 65

Table 6-2: Base Case Forecast Prices ........................................................................................ 66

Table 6-3: Methodology for calculating key outcomes relevant to OML 30 ................................. 68

Table 6-4: Capex Split .................................................................................................................. 69

Table 6-5: Assumed Oil prices for Brent Crude and OML30 ....................................................... 70

Table 6-6: OML30 Post-Tax Valuation (Net Heritage Share) ...................................................... 70

Table 6-7: OML30 Post-Tax Valuation (Net Heritage Share), Heritage alternative Income Tax Scenario ............................................................................................................... 71

Table 6-8: OML30 Reserves Summary ........................................................................................ 71

Table 6-9: OML30 Reserves Summary, Heritage alternative Income Tax Scenario ................... 71

Table 6-10: Sensitivity of OML30 NPV10 to Oil Price .................................................................... 72

Table 6-11: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share) .......................... 74

Table 6-12: Zapadno Chumpasskoye Reserves Summary ........................................................... 74

Table 6-13: Sensitivity of Zapadno Chumpasskoye NPV10 to Oil Price ....................................... 75

Table 6-14: Summary of Oil and Condensate Contingent Resources for Miran Field as of 31st March 2012 .......................................................................................................... 76

Table 6-15: Summary of Gas Contingent Resources for Miran Field as of 31st March 2012 ....... 76

RPS Ener

ECV 1851

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ECV 1851 3 July 2012

1.1 Liabilities The work programme associated with the PSA in Kurdistan is discussed in Section 5. In addition to the exploration work programme in the Kurdistan PSA, there was also a commitment to build a small refinery, which would have a capacity of 20,000 barrels of oil per day, in strategic partnership with the Kurdistan Regional Government (KRG). This commitment has now been waived in exchange for a future payment of US$35 million from Heritage to the KRG from future revenue received solely from production from the Miran Field.


ECV 1851 4 July 2012

2. METHODS USED IN THIS REPORT

2.1 General The evaluation presented in this Competent Persons Report (“CPR”) has been conducted within our understanding of petroleum legislation, taxation and other regulations that currently apply to these interests. RPS is not in a position to attest to the property title, financial interest relationships or encumbrances related to the properties.

Our estimates of potential resources and risks are based on the limited data set available to, and provided by, Heritage. RPS has accepted, without independent verification, the accuracy and completeness of these data.

Volumes and risk factors are presented in accordance with the 2007 SPE/WPC/AAPG/SPEE Petroleum Resource Management System (PRMS).

2.2 Reserves and Resource Classification Reserves or resources are estimated according to the 2007 PRMS. The PRMS Definitions are summarised in Appendix B.

In estimating reserves and resources RPS has used standard petroleum engineering techniques. These techniques combine geological and production data with detailed information concerning fluid characteristics and reservoir pressure. RPS has estimated the degree of uncertainty inherent in the measurements and interpretation of the data and has calculated a range of recoverable reserves. RPS has assumed that the working interest in each asset advised by Heritage is correct and RPS has not investigated nor does it make any warranty as to the Heritage interest in these properties.

Hydrocarbon resource and reserve estimates are expressions of judgement based on knowledge, experience and industry practice and are restricted to the data made available. They are, therefore, imprecise and depend to some extent on interpretations, which may prove to be inaccurate. Estimates that were reasonable when made may change significantly when new information from additional exploration or appraisal activity becomes available.

2.3 Risk Assessment For all prospects and appraisal assets estimates of the commercial chance of success for Contingent Resources, and estimates of geological chance of success for Prospective Resources, have been made. In PRMS the former is called Chance of Development (CoD) and the latter Chance of Discovery (also CoD) in the PRMS system. To avoid confusion with acronyms RPS has used the term Geological Probability of Success (GPoS) in this document synonymously with Chance of Discovery.

2.3.1 Contingent Resources The chance of success in this context means the estimated chance, or probability, that the volumes will be commercially extracted.

A Contingent Resource includes both proved hydrocarbon accumulations for which there is currently no development plan or sales contract and proved hydrocarbon accumulations that are too small or are in reservoirs that are of insufficient quality to allow commercial development at current prices. As a result the estimation of the chance that the volumes will be commercially extracted may have to address both commercial (i.e. contractual or oil price considerations) and technical (i.e. technology to address low deliverability reservoirs) issues.

2.3.2 Prospective Resources (Exploration Prospects) Unlike risk assessment for Contingent Resources, when dealing with undrilled prospects there is a more accepted industry approach to risk assessment for Prospective Resources. It is standard practice to assign a Geological Probability of Success (GPoS) which represents the likelihood of source rock, charge, reservoir, trap and seal combining to result in a present-day hydrocarbon accumulation. RPS assesses risk by considering both a Play Risk and a Prospect Risk. The chance of success for the Play and Prospect are multiplied together to give a Geological Probability of Success (GPoS). We consider three factors when assessing Play Risk: source, reservoir, seal and we consider four factors when assessing Prospect Risk: trap, seal, reservoir and charge. The result is the chance or probability of discovering hydrocarbon volumes within the range defined (Section 2.4). It is not an estimation of commercial chance of success.


ECV 1851 5 July 2012

2.4 Uncertainty Estimation The estimation of expected hydrocarbon volumes is an integral part of the evaluation process. It is normal practice to assign a range to the volume estimates because of the uncertainty over exactly how large the discovery or prospect will be. Estimating the range is normally undertaken in a probabilistic way (i.e. using Monte Carlo simulation), using a range for each input parameter to derive a range for the output volumes. Key contributing factors to the overall uncertainty are data uncertainty, interpretation uncertainty and model uncertainty.

Volumetric input parameters, gross rock volume (GRV), porosity, net-to-gross ratio (N:G), water saturation (Sw), fluid expansion factor (Bo or Bg) and recovery factor, are considered separately. RPS has internal guidelines on the best practice in characterising appropriate input distributions for these parameters.

Systematic bias in volumetric assessment is a well-established phenomenon. There is a tendency to estimate parameters to a greater degree of precision than is warranted2 and to bias pre-drill estimates to the high side3. Rose and Edwards observe the tendency towards assessing volumes in too narrow a range with overly large low-side and mean estimates. RPS uses benchmarked P90/P10 ratios and known field size distributions to check the reasonableness if estimated volumes.

2 Rose, P.R., 1987. Dealing with Risk and Uncertainty in Exploration: How Can We Improve? AAPG Bulletin, 71 (1), pp. 1-16.

3 Rose, R.P. and Edwards, B., 2001. Could this prospect turn out to be a mediocre little one-well field? Abstract, AAPG Bulletin, 84(13).


ECV 1851 6 July 2012

3. OML30

OML 30 is situated in the onshore Niger delta, a prolific oil producing region. The licence covers 1,097 km2 and contains 11 producing fields, Afiesere, Eriemu, Evwreni, Oweh, Olomro-Oleh, Kokori, Oroni, Uzere West, Osioka, Ofa and Okpolo) each of which contains up to 44 individual stacked sands. Ofa and Okpolo are marginal fields with no value as these have been licenced to third parties and Osioka has upside potential only (P3). The Operator has stated that three fields straddling the licence boundary should be considered for unitisation. These fields are not included in the report. This report has assessed the potential from the 8 remaining major fields comprising a total of 116 reservoir production profiles. OML 30 contains nine flow stations with a combined capacity in excess of ca. 395 kbbl/d. These include five single-bank, two-stage separation flowstations: Eriemu, Evwreni, Oroni and Oweh (each with 30 kbbl/d capacity); and Osioka (5 kbbl/d); and four double-bank, two-stage separation flowstations: Kokori (90 kbbl/d), Afiesere, Uzere, and Olomoro-Oleh (each with 60 kbbl/d capacity). OML 30 liquids are transported through the easterly section of the TransForcados Pipeline (TFPL) to the Ughelli Pump Station (UPS), located within OML34, and then westwards to the Forcados Pipeline Terminal for export. The UPS and TFPL are owned by OML 30. Reservoir pressures are supported by a strong aquifer thus removing the requirement for pressure maintenance. Artificial lift is accomplished by gas lift and most wells have gas lift installed. Low-pressure gas released from Joint Venture oil field operations in OML 30 is collected from six flow stations (Afiesere, Eriemu, Kokori, Olomoro-Oleh, Oweh and Uzere) and compressed at site via Nigerian Gas Company (NGC) owned associated gas compressors. Collectively these compressors amount to some 42 MMScf/d of capacity. An NGC pipeline receives the compressed gas and routes the combined flow via Ughelli Flow Station (located within OML34) for distribution into the local low-pressure domestic demand network. Shell has been operating the licence since 1963. In recent years there have been a number of shutdowns due to sabotage of flowlines and equipment, etc. and currently there are a number of wells that have been shut-in. The main reason for wells being shut-in or operating at less than optimal rates is a lack of gas lift due to compressor failures etc and vandalism of flowlines. Shell’s 2006 plan identified a number of horizontal well drilling targets and also identified actions to re-open or optimise production in existing wells. It is these actions together with new wells that form the basis of Heritage’s development plan for the licence.

3.1 Data Available The fields are mature producing fields and data provided reflects the current stage of development. RPS has been provided with historical production data by reservoir up to July 2010 in graphical format for the majority of the producing reservoirs. These plots have been scanned by RPS and data has been digitised and converted to OFM format. Heritage also provided production data by well and field in electronic format for 2H 2010, 2011 and 1Q 2012. Heritage has provided a Field Development Plan (FDP) in the form of a spreadsheet listing closed-in wells (as of 2010) to be re-opened and new horizontal wells to be drilled. Shell’s 2010 well surveillance report and well test sheet has been provided. Other information provided for each field includes; Shell’s tables of recoveries and reserves by reservoir (1/1/2010), selected maps; Shell’s 2009 field summaries and drilling plans; Scope For Recovery (SFR) Initiation Notes (2006) and Shell’s previous Field Development Plans (circa 1995 – 2009).

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ECV 1851

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ECV 1851

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ECV 1851 9 July 2012

field consists of 44 oil reservoirs from -1,900 mSS to -4,100mSS. Forty one of the reservoirs were originally under-saturated. The sands are quite well correlated throughout the field. There is no significant internal faulting.

3.2.6 Kokori Kokori consists of 60 hydrocarbon reservoirs. However 80% of the STOIIP lies in 13 main reservoirs. The field is a roll-over anticline, sealed to the North by a south hading growth fault. The reservoirs are estuarine channel complexes incised into shoreface sands/heterolithics. Most reservoirs are coarsening upwards shoreface deposits. Channel sands have the best reservoir quality and trend perpendicular to the growth fault. The field was discovered in 1960 and has been produced since 1966. The shallow reservoirs contain particularly viscous crude with viscosities in the order of 55 cp to 100 cp.

3.2.7 Oroni Oroni forms part of a WNW-ESE trending roll-over anticline with Uzere West. Oroni is the most westward of the fields and is separated from Uzere West at deeper levels by a saddle. The field consists of stacked anticlinal reservoirs at depths between -2,260 mSS and -3,970 mSS which are mostly dip-closed but become fault closed at some levels. The reservoir sands consist mainly of channel and shoreface deposits. Both Oroni and Uzere West were discovered in 1965 with first oil in 1970. The field contains medium quality crude which has in-situ viscosity of between 0.3 cp and 2.9 cp. Hydrocarbons were encountered in 38 reservoirs most of which have thin oil rims with oil columns of between 7.6 and 16.8m. Sand production has been a problem in this field and most of the work-over activities have been for the purposes of sand exclusion.

3.2.8 Uzere-West Uzere-West forms part of a WNW-ESE trending roll-over anticline with Uzere-West. Uzere-West is the most eastward of the fields and is separated from Oroni at deeper levels by a saddle. The field consists of stacked anticlinal reservoirs at depths between 2,260 mSS and 3,960 mSS which are mostly dip-closed, but become fault closed at some levels. The reservoir sands consist mainly of channel and shoreface deposits. Both Oroni and Uzere West were discovered in 1965 with first oil in 1970. The field contains medium quality crude with in-situ viscosity of between 1.4 cp and 3.9 cp. Eleven reservoirs have been produced to date. Reservoir pressure is supported by a strong aquifer.

3.3 In-place Volumes All the fields have substantial production histories, thus reserves estimates were undertaken by decline analysis. This analysis is completed independently of the in-place volumes. However, in-place volumes have been used where it is necessary to allocate production between reservoirs in the case of commingled production, and in assigning a reservoir maximum recovery factor cap. For these calculations RPS has utilised the Shell estimates of in-place volumes.

Sufficient geological data was unavailable to validate the Shell volumes. A comparison was, however, performed on some of the reservoirs. Five sands, from four fields, were used as examples. Top reservoir depth contours were digitised into Logicom’s REPTM stochastic modelling progam (REP) from the image maps provided and constant gross thickness, porosity, NTG and fluid parameters were assumed as provided in the Shell documentation. It is noted that the limited data only allowed an approximate estimate of in-place volumes to be made. Table 3-1 summarises the comparison.


ECV 1851 10 July 2012

FIELD AFIESERE OLOMORO- OLEH KOKORI AFIESERE ERIEMU AFIESERE ERIEMU

Reservoir M1000 P0000 L2800 J3100X J3100X J2090X J2090X

Shell (MMstb)

89 40 54 107 96 212.5 65.2

RPS (MMstb)

115 43 70 144 107 175 112

Ratio 129% 108% 130% 134% 112% 82% 172%

Table 3-1: Approximate Oil In-place Volumes from Shell Maps and Average Parameters

The RPS calculations are typically 8% to 30% higher than these Shell volumes. The J2090X reservoir is contiguous through the Afiesere and Eriemu fields and when these are considered jointly are within 3% of the Shell volume. Given that the volumetric data was used infrequently within this review. RPS considers that it is generally appropriate to use the Shell STOIIP volumes. In a number of reservoirs, the current recovery factors, based on the Shell STOIIP, are unrealistically high (up to 70%), indicating that the Shell calculated STOIIP is too low. In these reservoirs, the maximum recovery factor cap has been adjusted accordingly to account for the discrepancy.

3.4 Assessment of Resources Technically recoverable resources were estimated for each of the producing reservoirs. This included estimation of reserves for the planned 218 new wells, restoring 60 wells to production and gas-lift maintenance to restore optimum gas lift to all wells. Heritage’s original development plan was based on field information in 2010. RPS has since received well by well production data for 2010 to 2012 and several of the planned wells have since been restored. RPS forecasts utilise the most recent information. Historic production by field since July 2010 is shown in Figure 3-3.

Figure 3-4: OML30 Production Data (from July 2010)

Decline curve estimation of resources is ideally completed on a well by well basis. However, as early production data prior to 2010 was unavailable by well or by string (most wells are dual completions), this work was completed on a reservoir by reservoir basis. For the wells/strings being brought back

0

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ECV 1851 11 July 2012

on stream initial rates are based on the last well test rate adjusted for water encroachment since shut in. In a few cases where flow is commingled from two or more reservoirs, the status of each reservoir has been considered when making adjustments for water encroachment.

Currently the fields are producing inefficiently with intermittent gas lift caused by a shortage of gas-lift gas due to necessary compressor maintenance and refurbishment. RPS considers that the necessary flowline and compressor repairs can be carried out in 2012 or early 2013 so that wells will operate at optimum rates from 2013 onwards. More detail can be found in subsequent sections.

A number of important caveats should be highlighted in the assessment of the Reserves:

1) The reserves estimates are based on Heritage’s development plan provided to RPS. No associated gas (as solution gas with the oil or as coned in gas-cap gas) has been taken into account in the reserves assessment and subsequent valuation. Gas will be used for fuel or sold on the local market and is assumed to have no net value. Shell estimates the fields contain 2P gas reserves of 2.5 TCF. Development of these resources is not included in this report.

2) It has not been possible to independently verify the STOIIP. The data provided is too limited and only allows an approximate estimation of in-place volumes. Based on RPS’s check we are able to say that the Shell volumes look reasonable. Recoveries per reservoir are largely assessed from decline analysis. However, volumes in-place have been used to determine the maximum reservoir recovery.

3) The volumes provided within tables in section 3.4 are technically recoverable volumes prior to the application of an economic cut-off.

3.4.1 Rationale for Subdivision Heritage has provided a development plan listing wells, field activities and costs. RPS has reviewed this plan and applied a number of revisions based on its independent assessment. This plan has been updated as more information became available.

Heritage’s development plan includes optimisation of gas lift in existing wells (both producing and non-producing), reopening wells currently shut-in and drilling a number of new, mainly, horizontal wells. The shut-in wells that will be re-opened are taken from the latest RPS modified plan and all new wells identified by Heritage in their drilling plan are assumed to be drilled. In determining the drilling schedule it has been assumed that six rigs will be available with one new rig starting up every six months from 2014 and that six wells can be drilled per rig per year. It is assumed that three workover rigs will be available during 2013 and each workover rig can perform up to 26 workovers a year.

For the purpose of costing and forecasting the existing wells were subdivided in to producing wells and shut-in wells.

Historic production data to July 2010 has been provided by reservoir for the majority of the important

reservoirs (although some minor reservoirs are missing). Production data by well, string and reservoir has also been provided from Jan 2010 to March 2012. The lack of early production data by well has required the analysis to be performed by reservoir. The reservoir data has been subdivided in a number of groups:

• Reservoirs with historic production data

• Reservoirs that have produced but for which RPS has no available data (missing reservoirs)

• Producing reservoirs with missing historic production data, but with recent production data by well Historic production data by reservoir has been combined with the most recent well data to provide a complete dataset of production data by reservoir to complete the reserves evaluation.

3.4.2 Decline Curve Analysis (DCA) Methodology Recoverable volumes for each reservoir with sufficient production history were estimated using decline curve analysis. Most of the producing reservoirs have a strong aquifer drive recovery mechanism and the existing wells are producing at medium to high water-cuts. Established water-cut and water-oil-ratio trends are observable for all reservoirs. Recoverable volumes were estimated by extrapolating historical water-cut and water-oil-ratio trends. Decline curves have been generated for


ECV 1851 12 July 2012

the 1P and 3P cases as described below. The 2P case is estimated to be midway between the 1P and 3P cases.

The Proved (1P) recoverable resources from existing wells were estimated using a linear water-cut versus cumulative oil trend. Proved plus Probable plus Possible (3P) recoverable resources were estimated using a semi log water-oil-ratio versus cumulative oil trend. In determining the remaining resources from existing wells (PDP) an abandonment water-cut of 95% has been assumed. Figure 3-5 and Figure 3-6 show examples of the historical and forecasted water-cut and water-oil-ratio trends for the 1P and 3P cases.

Figure 3-5: 1P Example – Water-cut versus Cumulative Oil Plot L8000X Reservoir Kokori

Figure 3-6: 3P Example - Semi Log Water-Oil-Ratio versus Cumulative Oil Plot L8000X

Reservoir Kokori

0 20000 40000 60000 800000

20

40

60

80

100W

ater

cut (

%)

Cum, Mbbls

Case Name : 1PSlope : 0.00304782Intercept : -50.8162Start WCT : 84.2432 End WCT : 95 Cum. Prod. : 44313.5 MbblReserves : 3529.35 MbblEUR : 47842.8 Mbbl

0 15000 30000 45000 600000.001

0.01

0.1

1

10

100

WO

R

Cum, Mbbls

Case Name : 3PSlope : 7.04401e-005Intercept : 0.00446247Start WOR : 5.9 End WOR : 59 Cum. Prod. : 44313.5 MbblReserves : 14196.5 MbblEUR : 58509.9 Mbbl


ECV 1851 13 July 2012

3.4.3 Existing Producing Wells (PDP) The watercut and water:oil ratio (WOR) vs cumulative oil decline curves were converted to oil rate vs time plots to generate forecasts by reservoir for the existing producing wells only, i.e. the PDP (currently producing) case.

The initial (2012) forecast rate for each field, apart from Uzere West which is currently shut in, is based on the historic average rate for 1st Jan – 31st March 2012. For the 1P case it is assumed that the average 2012 rate will be the same as the historic rate; for the 2P case, the historic rate is assumed, but with an uplift to remove the effect of a two week shut down for a leak in the Trans Forcados Pipeline (TFP). The 3P initial rate is taken as the 2P case + 20%.

The Uzere West field has been shut in since December 2011 while negotiations with the Uzere West community are in progress. Heritage has advised us that these issues are nearing completion and should be wrapped up and production recommence in July 2012. In generating PDP forecasts, RPS has assumed that the existing Uzere West wells produce at their last producing rate from 1 September 2012 for the 2P case. The 1P and 3P cases are -+20% of the 2P rate.

These forecasts are truncated at the end of the lease period in 2049.

3.4.4 Wells Currently Shut- in (PDNP) The 2P initial rate for existing wells that are brought back on stream is assumed to be the last measured rate for the well. The 1P and 3P initial rates are assumed to be the last measured rate for the well +/- 10% respectively. Where wells have been shut-in for some time, rates are discounted to reflect that the OWC may have moved during the intervening years.

In light oil reservoirs the OWC can be assumed to move upwards fairly uniformly as there are very few faults present. Production since 2009 has been minimal so it is expected that the OWC will not have moved significantly. Therefore in reservoirs with oil viscosity < 9 cp, initial rates for wells that are located close to the POWC4 have been discounted by approximately 5% for every year the well was shut-in prior to 2009.

In viscous oil reservoirs, the water displacement is unstable and water breakthrough occurs due to viscous fingering or water under-ride rather than a steady OWC rise. Interference between wells is small. In reservoirs with oil viscosity > 9cp well rates are only discounted for wells that are close to the original OWC and were shut-in prior to 2000.

Incremental rates for each reservoir due to currently shut-in wells coming on stream have been calculated and forecasts generated assuming the 1P and 3P declines from section 3.4.3.

3.4.5 Gas Lift Optimisation (PDP & PDNP) It is assumed that full gas lift optimisation will increase well rates by a factor of 1.25, 1.35 and 1.45 for the 1P, 2P and 3P cases respectively. These factors are based on the production fluctuations observed during the intermittent gas lift in 2011. Gas lift optimisation is applied to both currently shut- in wells and currently producing wells from 2013 onwards. For existing producing wells, the incremental rate as a result of gas lift optimisation is added from 2013. For currently shut-in wells the well is assumed to come on stream at the optimised rate.

3.4.6 New Wells (PUD) Heritage Oil’s plans are to further develop OML30 by drilling additional, mainly, horizontal development wells. Heritage has provided RPS with a plan detailing the additional wells to be drilled. A total of 184 horizontal wells, 18 deviated and 16 vertical wells into 116 formations in 8 fields are planned. Initial rates and recoverable volumes for the proposed new wells were estimated depending on the type of formation being targeted.

These reservoirs have historically been produced with vertical wells. Horizontal infill wells are now being proposed. RPS has analysed available production data for existing horizontal wells in the Kokori field and the Eriemu fields (Well 21 ST) and analogue data from the Batan field to determine the ratio of horizontal to vertical well initial average rates. Based on this data, the following multipliers have been applied to the average gross vertical well rate to obtain the starting rate for new wells.


ECV 1851 14 July 2012

Well Type P90 P50 P10

Vertical .9 1 1.1

Horizontal 1.5 2 3

Deviated 1.25 1.5 2

Uncertain .9 1.5 2

Table 3-2: Horizontal/Vertical Well Factors for < 5 cp Reservoirs

Well Type P90 P50 P10

Vertical 0.9 1 1.1

Horizontal 1 2 3

Deviated 1 1.5 2

Uncertain 0.9 1.5 2

Table 3-3: Horizontal/Vertical Well Factors for > 5 cp Reservoirs

3.4.7 Recovery Factor In generating the 1P, 2P and 3P forecasts RPS has capped the recovery factor at what is considered to be a reasonable maximum, based on the reservoir type and the reserves category. These caps are based on RPS’s experience of analogue fields and have been confirmed using RPS’s Maestro tool which uses analytical methods to estimate recovery factor based on a number of performance indicators including viscosity/gravity values and sweep efficiency algorithms. For the viscous oil reservoirs, recovery factor caps have been confirmed by analogy with current and ultimate recovery factors for a number of worldwide viscous oil reservoirs. The following recovery factor caps have been applied.

1P 2P 3P

Light Oil < 5cp 35% 47.5% 60%

Moderate Oil >5cp and <20cp 25% 35% 45%

Moderate Oil >5cp and <20cp with Gas Cap 20% 30% 40%

Viscous Oil > 20cp 20% 27.5% 35%

Viscous Oil > 20cp with Gas Cap 15% 22.5% 30%

Table 3-4: Maximum Recovery Factors Applied

In a number of reservoirs, either the current recovery factor or the PDP reserves attributable to existing wells, exceeds the recovery factor cap. This is most likely due to either STOIIP estimate errors or due to production allocation errors either between reservoirs within the same field or between fields where the same reservoir is contiguous. Where this occurs, the recovery has been capped at the EUR based on decline analysis of existing wells prior to any economic or lease cut off.

3.5 Production Forecasts Individual reservoir 1P production forecasts have been constructed by summing PDP, PDNP and PUD forecasts as described above. The 3P production forecasts are constructed in a similar manner, but using the 3P estimates as described above. The forecasts for each reservoir are summed to provide the field forecast. The 2P field forecasts are assumed to be the average of the 1P and 3P forecasts. It is noted that the RPS reserves estimates are only for the reservoirs currently targeted to be developed.

Full production histories for all reservoirs were unavailable. Where production data covering 2010 – 2012 was available, this data has been used to estimate reserves. A number of reservoirs have been developed but are not currently producing. In estimating reserves it is assumed there will be no further production from these reservoirs.


ECV 1851 15 July 2012

Technical Resources for each field, to the end of the production licence in 2049, are described in Tables 3-5 to Table 3-11 and the production forecast plots for each field are described in Figure 3-6 to Figure 3-12.

The Technical Resources for the licence are given in Figure 3-14 and Table 3-12. RPS has confidence in the Technical Resources and EUR values that have been determined. The recovery factors described are subject to possible inaccuracies in the Shell estimated STOIIP data and are less certain.

1P 2P 3P

EUR (MMstb) 454 637 846

Remaining Technical Resources1 (MMstb) 184 368 577

RF 27% 34% 40% Notes

1. Before economic cutoff

Table 3-5: Expected Ultimate Recovery and Remaining Technical Resources for Combined Afiesere and Eriemu Fields

Figure 3-7: Production Forecasts for Afiesere and Eriemu Combined

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ECV 1851 16 July 2012

1P 2P 3P

EUR (MMstb) 525 646 779

Remaining Technical Resource 1 (MMstb) 135 260 390

RF 2 40% 45% 50% Notes

2. Before economic cutoff 3. Includes Shell STOIIP discrepancies

Table 3-6: Expected Ultimate Recovery and Remaining Technical Resources for Olomoro -Oleh

Figure 3-8: Production Forecasts for Olomoro – Oleh

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ECV 1851 17 July 2012

1P 2P 3P

EUR (MMstb) 75 102 132

Remaining Technical Resources 1 (MMstb) 22 49 79

RF 26% 32% 36% Notes


Table 3-7: Expected Ultimate Recovery and Remaining Technical Resources for Evwreni

Figure 3-9: Production Forecasts for Evwreni

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ECV 1851 18 July 2012

1P 2P 3P

EUR (MMstb) 85 117 151


RF 31% 38% 44% Notes


Table 3-8: Expected Ultimate Recovery and Remaining Technical Resources for Oroni

Figure 3-10: Production Forecasts for Oroni

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ECV 1851 19 July 2012

1P 2P 3P

EUR (MMstb) 446 551 659


RF 2 44% 44% 42% Notes


Table 3-9: Expected Ultimate Recovery and Remaining Technical Resources for Kokori

Figure 3-11: Production Forecasts for Kokori

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ECV 1851 20 July 2012

1P 2P 3P

EUR (MMstb) 183 249 324


RF 2 43% 49% 55% Notes


Table 3-10: Expected Ultimate Recovery and Remaining Technical Resources for Uzere-West

Figure 3-12: Production Forecasts for Uzere-West

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ECV 1851 21 July 2012

1P 2P 3P

EUR (MMstb) 162 194 228


RF 2 53% 58% 63% Notes


Table 3-11: Expected Ultimate Recovery and Remaining Technical Resources for Oweh

Figure 3-13: Production Forecasts for Oweh

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ECV 1851 22 July 2012

1P 2P 3P

EUR (MMstb) 1930 2496 3119

Remaining Technical Resources 1 (MMstb) 544 1,119 1,739

RF 2 36% 41% 45% Notes


Table 3-12: Expected Ultimate Recovery and Remaining Technical Resources for OML30

Figure 3-14: Production Forecasts for OML30

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ECV 1851 23 July 2012

3.6 Facilities and Cost Estimates Capital, drilling, operational and abandonment costs have been based on recent Heritage studies together with RPS in-house data. RPS has used these costs to develop 1P, 2P and 3P cases.

3.6.1 Capital Expenditure

Facility Costs (US$MM)

1P 2P 3P Facility Infrastructure $52.0 $69.0 $104.0 Workovers for Wells Shut-In $42.8 $60.5 $60.5 Flowline Repairs $12.2 $12.2 $12.2 Gas lift Restoration $37.5 $40.5 $40.5 Compressor Maintenance $3.5 $7.0 $7.0 Indirects @ 17.5% (RPS) $25.9 $33.1 $39.2 Contingency @ 20% (RPS) $34.8 $44.5 $52.7 FACILITIES TOTAL $208.6 $266.8 $316.1

Table 3-13 Nigeria OML30 Facility Costs (US$MM)

Capex costs include all necessary expenditures to repair the existing infrastructure and open up the non-producing wells.

RPS has added indirect costs at 17.5% for Engineering, Project Management, Certification, Insurances, etc. A contingency allowance of 20% has been applied to the base and indirect costs in line with the industry standards and banking requirements

Included in the capital costs are the following:

OML 30 General Infrastructure Costs: Costs for the refurbishment and modification of existing storage tanks and returning them to their original dewatering plant usage at the Ughelli Pumping Station (UPS) have been included. The UPS will handle all fluids from OML 30 fields. Other general costs include fiscal and local metering, the Forcados Pipeline refurbishment, environment audits and general take-over costs.

Field Infrastructure Costs: Costs have been included where necessary for rebuilding, repair, general maintenance, refurbishment and upgrading of the main flow stations and gas lift compressor stations servicing each field.

Initial Well Maintenance and Workover Costs: Initial well maintenance is planned to bring on all viable proven non-producing wells. The workover activity in this initial phase typically includes restoring gas lift, well cleaning, gas lift optimisation and general opening up of suspended wells. Some individual wells require more specific re-perforating and recompletion activities. The well surveillance information generated by SPDC in 2010 and supplemented by the most recent OFM data provides an up to date assessment and was used to assess the scope of work required on each well. To maximise early production benefits the schedule assumes that 3 workover rigs will be available in 2013/14 to carry out all necessary initial workover activity.

Flowline Repair and Compressor Repair Costs: The Well Surveillance Report indicates some oil and gas flowlines, connecting wells with the flowstations and gas lift compressor stations, as damaged. Appropriate costs have been included for flowline repair and restoring gas to those wells currently shut-in due to lack of gas for gas lift. Costs have also been included for repair and maintenance of gas lift compressors.


ECV 1851 24 July 2012

3.6.2 Drilling Costs Drilling of the new wells within the OML30 Block has been sequenced with the number of rigs available. It has been assumed that starting at the beginning 2014 with one rig, that an additional drill rig will be brought on every six months up to a maximum of six rigs. The fields are in generally dry terrain, with some seasonal flooding. The drilling programme has assumed a 60 day per well duration. A total of 34 vertical/deviated wells and 184 horizontal wells are assumed to be drilled at US$12MM per vertical and deviated well and US$15MM per horizontal well.

3.6.3 Operating Costs OPEX costs vary with production and peak at US$342MM in 2019 (2P Case). The OPEX includes fixed field costs and G&A together with variable well workover and lifting costs. Ongoing workover activity has been scheduled assuming one light workover per well every four years at a cost of US$200,000/well.

3.6.4 Abandonment Costs The following abandonment costs have been included:

• Removal of UPS pumping station and all field flow stations, gas stations and flowlines US$25MM per field or installation.

• Well abandonment costs are estimated at US$0.5MM per well.


ECV 1851 25 July 2012

4. ZAPADNO CHUMPASSKOYE

The Zapadno Chumpasskoye Licence is located in the West Siberian Basin in the Khanty-Mansyisk Province of Russia. Numerous producing oil fields operated by Lukoil surround Zapadno Chumpasskoye. The nearest city is Langepas located 8 km to the east. Heritage acquired the field in November 2005 from TNK-BP by acquiring a new special purpose vehicle, ChumpassNefteDobycha (CND), to operate and develop the field. Previous work on the licence included the drilling of nine exploration wells and the acquisition of several hundred km of 2D seismic.

In 2006 CND prepared the necessary approvals to commence work on the field, including gathering 202 km of new seismic, constructing a road, separation facility and drilling cluster to conduct further appraisal drilling and commence a pilot operation. An existing well, 226, was re-entered and four new wells have been drilled. Vertical wells P3, P4 and P226 have been producing since 2007 and a horizontal well, 363, commenced production in August 2011. Well P2ST serves as an injector. Well locations are shown on Figure 4-1.

On May 27, 2007, the Russian authorities approved Phase 1 of the development, consisting of reservoir studies and early wells to establish the efficacy of a full field development (“FFD”) using an inverted 5-spot pattern. That initial approval covers the drilling of up to 53 wells including 13 injection wells. However, following falls in the oil price, planned drilling in 2008 and 2009 was deferred until the price recovered. In 2009, Heritage submitted another field development plan (“FDP”), this time based on a pilot scheme using horizontal or high angle wells, and hydraulic fracturing. The latest well drilled (well 363) is the first of the pilot scheme wells. The Company will have to resubmit its FDP (for the FFD) for approval once the efficacy of using horizontal wells has been established.

4.1 Data Available Data from the surrounding fields are sparse because competitor data is proprietary. A variety of data were available for this review. Seismic data coverage (2006 survey and the older data) comprises 2D lines shot at fairly wide spacing. A number of Russian-drilled wells were available with Russian style wireline logs limited to SP, Conductivity and the Russian BKZ gradient (lateral) logs with 2.25 electrode spacing. Two new wells were drilled in 2007 (P3 and P2) and a third (P4) was drilled in 2008. New wells, drilled since 2007 by Heritage, have modern western-style logs.

DST data from new wells, summaries of previous reservoir simulation studies and production data from wells 226, P3, P2, P4 and 363 were provided. Since the 2009 study by RPS, the Operator has located an old well, well “No 14”. The well has since been logged and shown to contain only water in the Jurassic, with some prospectivity in the Cretaceous. The Operator has also located data from wells 7 and 118. In addition, there is some hard and anecdotal information/data from some of the Lukoil wells that surround the subject license.

RPS was also provided with the 2009 Field Development Plan (FDP) for completeness.

4.2 Geology

4.2.1 Regional Setting The Upper Jurassic sequence in the Zapadno Chumpasskoye Licence is understood to comprise a sequence of shallow marine clastics, which are widely deposited in the West Siberian Basin. The Upper Jurassic is some 60 to 70 m thick and includes a lower section of claystones and an upper sand sequence interbedded with siltstones and claystones. The Upper Jurassic in the area is overlain by the Bazhenov Formation, a 20 to 25 m thick bituminous shale, which is both the source and the cap rock for the reservoir.

The six fields surrounding Zapadno Chumpasskoye are also reported to be producing from the Upper Jurassic.

4.2.2 Zapadno Chumpasskoye Field Prior to the wells drilled since 2007, Heritage presented a correlation of the upper part of an Upper Jurassic clastic sequence based on lithostratigraphy (no biostratigraphic data was available). Two sandstone intervals (the Upper and Lower J1 Sandstones) were identified in the upper part of the sequence and correlated between most of the wells using the SP logs. These occur below the base of the ‘low conductivity zone’, equating to the Bazhenov shale which is the seal and source rock for the Jurassic reservoirs. The correlation has been revised based on data from the new wells and the additional older well data that has become available to Heritage.


ECV 1851 26 July 2012

The data from the Russian drilled wells available for evaluating net sand, net pay and fluid contact is limited to SP, Conductivity and the Russian BKZ gradient (lateral) logs with 2.25 electrode spacing. These are low resolution tools and the resistivity logs are unfocused. There are no porosity logs. The SP logs were normalised to enable a consistent comparison of sand quality between wells. Net sand was initially picked at a typical VCL cut-off of 50%. However, to compensate for the low resolution of the SP and the presence of thin beds, a higher VCL cut-off was accepted for the thinner layers (i.e. thickness less than 5 m). The Russian lateral logs were reviewed for evidence of hydrocarbons in the wells and to determine the fluid contacts. The log response is asymmetrical and only a qualitative interpretation was possible. The Upper J1 hydrocarbon bearing sands were found to have resistivities only occasionally exceeding 10Ώm and are typically around 7-8Ώm. Resistivities over the deeper Lower J1 formation, closer to the hydrocarbon-water contact, tended towards 15Ώm. The resistivity measurements in some of the thinner sands were uncertain due to poor log resolution.

The revised interpretation suggests that the Upper J1 Sand is very localised and no volumes are now assigned to this sand. Well spacing is large in this licence (between 2 and 7 km) and lateral variations in sand content and quality, plus sand pinch-outs and amalgamations, are likely to occur within such distances. The model of pinch-out of the Upper Sand onto the high in the south is a reasonable interpretation of the logs and is supported by evidence from well P2.

Seismic data quality in this licence is moderate. However, the frequency content of the data at reservoir level is insufficient to define the reservoir thickness. Effectively, the only presently perceived use for this dataset is to define the structure at the top of the reservoir sequence which is seen to be a simple north-westerly dipping surface.

Heritage provided depth structure maps at Top Upper Sand levels. Seismic data have been reviewed. No faults are shown on the maps, but it is possible that faults may cut the sequence and offset the relatively thin (generally less than 10 m) sands. Due to the stratigraphic nature of the trap, seismic interpretation is not regarded as critical to the volumetric evaluation.

As noted above, RPS were provided with an FDP for the field. The FDP contains a series of net pay maps in Appendices 3 and 6 created by the FDP author. However, Heritage’s current Net Oil Pay thickness maps (dated May 2010) were reviewed and modified as appropriate including an estimate of the pinch out edge to the south (the exact position of this pinch out cannot be precisely located on the seismic). The new well data did not make a material difference to the maps endorsed by RPS in the 2009 CPR. No definitive OWC has been identified, but possible fluid contacts were picked at 2,702 m TVDSS (deepest dry oil production in Well 226), 2,724 m TVDSS (ODT in Well 943) and 2,756 m TVDSS (possible ODT in Well 100). The Net Oil Pay thicknesses above each of these contacts were hand contoured, digitised and Net Pay Rock Volumes calculated. There is an ambiguous DST in well 220 which flowed water. The reservoir in this well (2689.3 m TVDSS) is slightly shallower than pay in well 220 (at 2702.6 m TVDSS). However, there are doubts about the effectiveness of the cement bond. The P90 net pay map assumes no pay in well 220 whereas the P50 and P10 net pay maps assume oil in well 220. Net pay values derived from wells drilled since May 2010 (P4st and P363 Pilot) have not materially impacted the in-place volumes. The revised P50 Net Pay Map is shown in Figure 4-1.

4.2.3 Petrophysics RPS undertook an independent petrophysical review of wells P2ST and P3 for the 2009 CPR. The Sw values interpreted from western logs in Well P3 were higher than expected. As a result a detailed review of core and water analysis data, derived from core taken from well P3, was undertaken. These data provided a basis for calibrating the logs from P2ST and P3. Well P3 was drilled with a water-based mud and was tagged with a fluorescent dye during coring. The core barrel contained a glass fibre inner barrel that was filled with depolarized mineral oil. To obtain the background reading of fluorescent dye concentration, the tagged mud was sampled regularly during coring. However, no fluorescence was detected from the water extracted from the core and it is therefore considered that the core did not suffer filtrate invasion in the volumes sampled for water extraction; consequently no invasion corrections were applied.

Full details of the petrophysical analysis undertaken by RPS are given in the 2009 CPR.


ECV 1851 27 July 2012

Figure 4-1: Lower J1 Sand – RPS Net Pay Map (P50 Case)

For wells P2ST (all zones) and P3 (zones LCa and LCb only) porosity was derived using the density/neutron crossplot method. For Zone LCc in P3 the density log was used on its own for porosity determination.

For both wells, total water saturation was calculated using the Archie equation4. Effective water saturation was derived using the shaley sand “Indonesia” Equation of Poupon and Leveaux5.

4 Archie, G.E. “The Electrical Resistivity Log as an Aid in Determining Some Reservoir Characteristics”. Petroleum Transactions of the AIME 146 (1942).

5 Poupon, A and Leveaux, J “Evaluation of Water Saturation in Shaly Formations”. SPWLA 12th Annual Logging Symposium, May 2-5 1971.


ECV 1851 28 July 2012

Owing to the silty and thin bedded nature of parts of the reservoir, it is possible that thin beds are not being resolved fully by tool responses and that the results of the interpretations have been influenced by smoothed tool responses.

4.2.4 In-place Volumes Porosity, saturation and formation volume factor ranges were estimated based on the RPS review of petrophysical data from wells P2ST and P3 and from the Operator’s interpretation of the older Russian wells. This interpretation was based on their regional knowledge and on assumptions that the reservoirs are analogous to those in the surrounding area. As a result of the differences in interpreted Sw, a broad range of Sw was used in the volumetric calculations. Input parameters are shown in Table 4-1.

Low Mid High

Net Pay Rock Volume (MM m3 ) 131 455 854

Porosity (%) 15 17 19

Oil Saturation (%) 45 60 65

Boi (rb/stb) 1.30 1.25 1.20

Table 4-1: Lower J1 Sand Input Parameters

STOIIP has been estimated probabilistically and is summarised in Table 4-2 below.

STOIIP (MMstb)

P90 P50 P10

90.3 233.0 419.0

Table 4-2: Zapadno Chumpasskoye, Lower J1 Sand, STOIIP Estimates (MMstb)

4.3 Petroleum Engineering

4.3.1 Reservoir Fluid Properties The Lower J1 Sand contains a highly undersaturated oil at an initial pressure and temperature of approximately 28 MPa (4,018 psia) and 96° C (205 °F), respectively, at a depth of 2,750 m. The produced oil has a density of 836 kg m-3 (~38° API). The in-situ viscosity of the oil is likely to be 2-3 times that of water, and the bubble point of the reservoir oil is 1,320 psia: the implication of these factors is discussed below. The initial solution GOR (Rsi) is 410 scf/stb, and the initial formation volume factor (Boi) is 1.25 rb/stb.

4.3.2 Well Performance & Deliverability RPS’ previous evaluation was issued in December, 2009 and had an effective date of 30th June 2009. Production to date is shown below in Figure 4-2 and Figure 4-3. The individual well rates at the end of March, 2012 were: 188 stb/d (well 226), 83 stb/d (P3), and 108 stb/d (P4). Well 363 was shut in in February 2012 and last produced at 361 stb/day. Heritage has recently advised us that the well has restarted since 31st March 2012. Cumulative production since start-up is 0.834 MMstb.

In 2009, well P2 was converted into an injector as planned, and well P4 was worked over to remedy water production and for the installation of artificial lift.

The field was shut-in between December 2008 and February 2009 following a temporary reduction in the domestic oil price in Russia. The field was returned to production with the current well stock, and the full field development (“FFD”) deferred to allow the local market prices to recover and stabilise. Heritage has now drilled one high angle well as the Phase II pilot scheme.

Clearly, with only four wells in production, the large majority of Reserves in the field (see Section 6) are classified as Undeveloped.


ECV 1851 29 July 2012

Figure 4-2: Zapadno Chumpasskoye Production History (Rate versus Time)

Figure 4-3: Zapadno Chumpasskoye Production History (Rate versus Cumulative)

4.3.3 Development Plan (Subsurface) On May 27, 2007, the Russian authorities approved Phase 1 of the development, consisting of reservoir studies and early wells to establish the efficacy of a full field development (“FFD”) using an inverted 5-spot pattern. Then, in 2009 approval was obtained for Phase II of the development consisting of a pilot scheme to establish the efficacy of horizontal wells. Whilst the FFD has not yet been approved we believe it is reasonably certain that such approval will be forthcoming, as it was for the first two of Heritage’s FDPs. The key points of the approved FDP are as follows:

• The FDP is based on Russian style “C1+C2” in-place volumes of some 176 MMstb6, from which 63.2 MMstb is recovered (a recovery factor of 36%, which is the State-Registered value);

6 Here and throughout, we have converted tonnes to stb using a conversion factor of 1 tonne = 7.52 stb, based on the average density quoted in the FDP.

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ECV 1851 31 July 2012

having been commissioned in 1995. Also of note in this mature field is that sustained rates of over 400 stb/d have been achieved from new wells in recent years.

The recent 363 well has demonstrated a productivity improvement factor of about 2 over the best producing vertical well in the Chumpasskoye field (P226) which supports the findings above.

To create our own independent life-of-field profiles, RPS has therefore assumed that further patterns of horizontal wells will be used throughout the field, but restricted to areas where net pay is greater than or equal to 4 m, and vertical wells used beyond this. RPS has assumed that the patterns would have eight horizontal wells; the pilot scheme has just six wells because it is in the area of existing wells (wells 226 and 3P are within the pilot scheme pattern area). This would lead to drainage areas of around 50 ha per horizontal well, compared to the previous design of 25 ha per vertical well.

4.3.4 Recovery Mechanisms Whist under natural depletion, wells will produce through oil expansion with perhaps some aquifer influx. It is unlikely that reservoir pressure will reach the bubble point at any point in the reservoir before water injection commences, so solution gas drive should not be developed. Once water injection commences, planned at a VRR in excess of one, the unfavourable mobility ratio will cause some of the water to create viscous fingers through the oil leg.

4.3.5 Production Profiles Inspection of Figure 4-2 and Figure 4-3 shows early evidence of a decline trend at both the field and well scale. The decline trends seen are consistent with our earlier estimates of URR/well and since there are no changes to our perception of reservoir quality or STOIIP, RPS has simply deferred our previous forecasts using the same assumptions on: well count and type, recovery per well, drilling and facility constraints, and so on. RPS has replaced every two vertical wells in the areas where net pay is greater than 4 m, with a single horizontal well, and RPS has also made short-term adjustments to honour the performance of the existing wells. The modified development results in the profiles as shown in Figure 4-5 to Figure 4-7.

Figure 4-5: RPS 1P Production Profile for Zapadno Chumpasskoye

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2-4Q2012

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032

Oil

Rat

e (s

tb/d

)


ECV 1851 32 July 2012



The summary output from the three RPS cases, at an effective date of 31 March 2012, combined with the STOIIP estimates from Section 4.2.4 above is given in Table 4-3 (commercial reserves are shown in the economic section, Section 6.4 below), simply reflecting the production of some 0.8 MMstb since our last evaluation:

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Oil

Rat

e (s

tb/d

)

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

Oil

Rat

e (s

tb/d

)


ECV 1851 33 July 2012

1P 2P 3P

STOIIP (MMstb) 90.3 233.0 419.0

LoF 1 URR 2 (MMstb) 25.0 69.7 172.7

LoF Recovery Factor (%) 28 30 41

URR/well (MMstb) 0.7 1.1 1.3

URR (MMstb), As At 31 March 2012 24.2 68.9 171.9 Notes 1. Life of Field, from start-up in 2007. 2. Ultimately Recoverable Resources – this may not be the finally quoted reserves (see

economics section) if economic analysis terminates the profile before this cumulative is reached.

There are no commercial gas reserves as all gas is and will be used in the field for fuel, flare pilot and so on, with the remainder flared. We are not aware of any limitations to the volume of gas that can be flared.

Table 4-3: Summary of Results for Zapadno Chumpasskoye

The recovery per well quoted above is higher than quoted in our previous evaluations, and it is higher than published data. For example, Lukoil publishes data for its proved reserves in Western Siberia, and has quoted up to 0.6 MMstb/well proved over the last few years for its well stock of over 15,000 wells in the region. However, the vast majority of these are vertical and in mature fields, and have been producing for some time.

As more and more published data on the basin becomes available, it has become clear that recovery factors of over 40% are achievable under secondary recovery, and the State carries an average recovery factor of over 36% for the Middle Ob region of Western Siberia, which is supported by the simulation work in the recent FDP. These higher recoveries are achieved through high angle or horizontal wells, hydraulic fracturing and EOR methods, all of which are becoming prevalent in Western Siberia.

A comparison of all the profiles is shown in Figure 4-8.

Figure 4-8: Comparison of all Profiles for Zapadno Chumpasskoye

4.3.6 Developmental Risk RPS has categorised these volumes as Reserves despite the prolonged absence of formal approval of a FFD as there is a reasonable expectation that all required internal and external approvals will be forthcoming, as they have been in the past. In addition, there is evidence of firm intention within Heritage to proceed with development within a reasonable time frame (as required under the PRMS guidelines). Heritage has given us a written assurance of its commitment to develop the field.

100

1,000

10,000

100,000

2007 2012 2017 2022 2027 2032 2037 2042

Oil Ra

te stb/day

History 1P 2P 3P


ECV 1851 34 July 2012

In each case, the majority of Reserves fall in the Undeveloped sub-category, meaning that significant investment and activity is required to exploit and monetise them. To quantify this roughly, we estimate that approximately 98% of the 2P LoF Reserves quoted above are Undeveloped, the Developed Producing 2% being the forecast from the existing well stock alone.

At this pre-production stage, there are the normal developmental risks, in addition to the obvious reservoir risks. These risks, which may impact the timing and amount of future cash flow – all standard at this stage of a development and by no means specific to Zapadno Chumpasskoye – include, but may not be limited to the following:

• The timing and any conditions of the formal approval by the Russian authorities of the development plan;

• The efficient functioning of the facilities;

• Tie-in to the adjacent Transneft pipeline to allow export of produced crude;

• The timing, location and results of the numerous development wells to be drilled;

• The installation and commissioning of new facilities of appropriate size for the production, processing and transportation of the produced oil;

• The raising of sufficient capital funds to cover these development costs.

4.4 Facilities and Cost Estimates Capital, drilling, operational and abandonment costs have been based on recent Heritage studies together with RPS in-house data. RPS has used these costs to develop a 1P, 2P and 3P case estimate.

4.4.1 Capital Expenditure

Facility Costs (US$MM) 1P 2P 3P Separation & Injection Facility $14.5 $29.4 $50.4 Field Infrastructure $10.7 $18.3 $35.0 Transneft Tie-In $17.5 $22.5 $32.7 Gas Pipeline to Lukoil Langepas Gas Plant $3.9 $3.8 $7.7 Other $5.5 $6.4 $6.4 Indirects @ 10% (RPS) $5.2 $8.0 $13.2 Contingency @ 20% (RPS) $11.5 $17.7 $29.1

FACILITIES TOTAL $69.0 $106.0 $174.5

Table 4-4: Zapadno Chumpasskoye Facility Costs (US$MM)

Capex costs have been estimated for each of the resource cases with throughputs ranging from 6,000 stb/d up to 44,000 stb/d. Costs include separation and injection facilities, field infrastructure, a metered tie-in to the Transneft pipeline and a gas pipeline to the Lukoil Langepas gas plant.

The Capex estimate has been developed assuming that equipment, materials and services will be sourced in Russia and all costs are based on Rouble denominated estimates and then converted to US dollars at 32 Roubles/US$

RPS has added indirect costs at 17.5% for Engineering, Project Management, Certification, Insurances, etc. A Contingency allowance of 20% has been applied to the base and Indirect costs in line with the industry standards and banking requirements.

4.4.2 Drilling Costs Production and water injection wells will be drilled in a series of clusters using both deviated and horizontal drilling techniques. The following drilling costs have been included.


ECV 1851 35 July 2012

1P 2P 3P

No. of Wells 64 97 171

Roubles (million) 4,032 6,304 10,650

US$ (million) 126 197 330

Table 4-5: Well Count and Well Costs

The drilling schedule is based on a rig being available in Q4 2012 and a second rig available in Q4 2013.

4.4.3 Operating Costs Opex costs have been estimated by Heritage and are judged as reasonable by RPS. The costs vary with production and peak at US$17MM per annum (2P case) and are made up of fixed field, general and administration costs and a variable lifting production cost and workover costs.

4.4.4 Abandonment Costs Abandonment costs vary according to plant size and well count. Plant removal costs of US$20MM and a well abandonment cost of US$0.25MM/well have been included.


ECV 1851 36 July 2012

5. KURDISTAN – MIRAN BLOCK

The Miran Block in Kurdistan lies within the western part of the High Folded Zone of Iraq and measures some 70 km by 15 km, elongated in a NW-SE direction. Exploration of the Block is still at a relatively early stage with two wells having been drilled and completed on the Miran West structure. A third well on Miran West has recently been completed and the first well on the Miran East structure is in progress.

Field mapping and seismic data has indicated the sub-surface presence of a large anticlinorium formed by two sub-parallel anticlines, separated by the NNW-SSE trending Tasluja Ridge, which has prominent topographic expression down the centre of the block. The Miran structure, which has a western and eastern culmination at shallower levels, lies adjacent to the Tasluja Ridge and was formed by mid-Tertiary compression which culminated with late stage thrusting during the Late Miocene. These anticlines have been covered by Quaternary and Recent deposits and now lack surface expression. The absence of a wide syncline between Miran West and Miran East reflects the partial thrusting of the latter over the former.

Faulting, both parallel (longitudinal) and orthogonal (transverse) to the fold axes, has been recognised from the seismic data and faults of this type partly delimit both the Miran West and Miran East structures. Results from analogue fields (e.g. Taq Taq) demonstrate that fracturing associated with this faulting can impart significant amounts of fracture porosity to otherwise essentially tight formations.

5.1 Available Data The Miran Licence Block is covered by 22 lines of 2D seismic totalling some 547 line km. Twelve of the lines totalling 333 line km were acquired in 2008 prior to the last report by RPS in 2009.

880 sq km full fold coverage of 3D seismic were acquired between October 2010 and August 2011 over the drilled Miran structure.

Ten lines of 2D seismic data totalling 214 km were acquired in 2011 after the acquisition of the 3D seismic survey. This 2D coverage, concentrated in the south of the licence block (Figure 5-1), was designed to delineate further prospects and leads.

Additional data from scout sources was provided to RPS which improved seismic correlation in the footwall of the Miran structure.

Two wells have been drilled and completed on the Miran West structure. A third well, Miran West-3 (M3) commenced drilling in August 2011 and has recently been completed. In March 2012 Heritage commenced exploration of the Miran East structure with the spudding of the Miran East-1 (M-4) well. This well is planned to take to take about 7 months to complete.


ECV 1851 37 July 2012

Figure 5-1: Miran Block Data Base Map

5.2 Wells on the Miran Structure

5.2.1 Miran West-1 (M1) Since the preparation of the RPS 2009 report Heritage has undertaken a re-survey of the drilling site which led to a revision of the RT elevation from +875m to +886.4m amsl. In addition, Heritage commissioned a detailed biostratigraphic study on Miran West-1 and as a consequence, some of the stratigraphic horizons and formation tops quoted previously have been revised.

Miran West-1, the first well drilled on the Miran West structure, was spudded in late 2008 as a vertical exploration well with primary targets of the Shiranish, Kometan and Qamchuqa Formations (Figure 5-2). A TD of 2935m MD (-2035m TVDSS) was reached during March 2009 in anhydrites and dolomites of the Lower Jurassic Adaiyah Fm.

Oil shows at shallow depth were first noted on fracture surfaces in limestones and claystones in the Upper Cretaceous (Late Maastrichtian) Tanjero Fm at 310m MD, (-576mTVDSS, i.e. amsl). These shows were not tested. Oil shows were recorded intermittently throughout the Upper Cretaceous (Shiranish, Kometan and Upper Balambo / Qamchuqa Fms) and Lower Cretaceous (Lower Balambo /


ECV 1851 38 July 2012

Sarmord Fms). Drilling was hindered by mud losses due to high mud weights. Oil was observed in the mud after returns had been regained at 1375m MD. This oil was in the range of 15 to 23˚ API with a GOR of c. 10 scf / bbl.

The well penetrated a thrust fault at about 1,970m MD, below which higher gas levels, but no further oil shows, were recorded in the Jurassic (Chia Gara, Barsarin, Sargelu, Alan Mus and Adaiyah Fms) intervals.

A full suite of standard wireline logs were acquired including XRMI image logs, analysis of which confirmed the presence of open fractures in the up-hole section. Heritage has interpreted these wireline data and identifies minimal matrix porosity throughout the well section. RPS has reviewed and endorsed this interpretation. None of the 43 attempted RFT pressure readings proved any permeability.

Five DSTs were run. DSTs #1 to #4 were unsuccessful and only the shallowest, DST #5, recovered oil to surface. Heritage re-tested selected intervals in August 2009 and on DST #5R obtained a pump supported flow rate of 3,100 Bopd of 15 ˚ API oil from the Shiranish Fm (see Section 5.4).

5.2.2 Miran West-2 (M2) Miran West-2 was spudded in November 2009 as a vertical appraisal / exploration well. It was located some 2 km NW along the crest of the Miran West structure initially targeting the Cretaceous and subsequently re-engineered to evaluate the exploration potential of the deeper identified Jurassic and Triassic structures.

The well reached TD at 4,426m MD (-3,502m TVDSS) in Triassic anhydrites of the Kurra Chine Fm during October 2010. A total of 18 (4” diameter) cores were cut, the recovery of which was very good. A full suite of standard wireline logs was acquired including XRMI / CMI image logs. The well was suspended as a gas condensate discovery in January 2011 after testing.

Limited evidence of open inter-connected fracturing was observed in the core and on both image and waveform sonic (WSTT) logs in the Cretaceous section. Wireline data from the lowest part of the Sarmord Fm suggests there may be some matrix porosity. Elsewhere there is minimal matrix porosity throughout the well sectionTwelve DSTs were run in Miran West-2, testing 6 intervals in the Cretaceous, 5 in the Jurassic and 1 in the Triassic. No test successfully flowed oil, but gas and condensate was flowed in DST #11 from the Jurassic and Lower Cretaceous (see Section 5.4).

5.2.3 Miran West-3 (M3) Miran West-3 was spudded in August 2011 targeting the Cretaceous and Jurassic reservoirs identified in the Miran West-1 and Miran West-2 wells with the aim of intercepting open fractures on the flanks of the structure. The well reached a total depth of 3,528m MD in May 2012 and Heritage has reported that the well had tested dry gas from a Jurassic reservoir above the main target at a rate of 17.5 MMscf/d. Heritage also report that testing of the main Jurassic reservoir resulted in a constrained flow of up to 22 MMscf/d of wet gas with a yield of 20bbl / MMscf of 55º API condensate.

5.2.4 Miran-4 (M4, Miran East-1) Miran-4 is the first well on the Miran East structure. Drilling commenced during March 2012 and is on-going. Prognosed TD is 4,000m MD with targets in the Cretaceous and Jurassic. Drilling is expected to take 7 months.

5.3 Structural Interpretation Seismic data quality is considered to be good above the main thrusts and in areas with less structural complexity, but is degraded in the deeper section in more highly deformed areas (Figure 5-2).

RPS Ener

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ECV 1851 41 July 2012

DST Depth (m MD)

Depth (m, TVDSS)

Stratigraphy Comment

Phase 1

DST #5A/5B/5C/5D 720 – 950 -166 (amsl) – 64 Shiranish See text below

DST #4 1,215 – 1,275 329 – 389 U. Balambo / Qamchuqa Flowed water

DST #3 1,334 – 1,390 448– 504 L. Balambo / Sarmord Flowed water

DST #2 1,430 – 1,655 544 – 764 L. Balambo / Sarmord Tight

DST #1 1,943 – 2,150 1,045 – 1,249 L. Balambo / Sarmord / Chia Gara

Tight – ‘puffs of gas’

Phase 2 (Re-test)

DST #5R 720 – 950 -166 (amsl) – 64 Shiranish Flowed 15 API oil

DST #4R 1,215 – 1,275 329 – 389 U. Balambo / Qamchuqa Flowed water

DST #3R 1,334 – 1,390 448 – 504 L. Balambo / Sarmord Flowed water

Table 5-1: DSTs in Miran West-1

DST #5 was perforated underbalanced with a diesel cushion. After an initial build-up the well was opened to clean up. Analysis of the pressure gauges indicated that the well would not flow naturally due to the lack of downhole pressure. DST #5D included a jet pump and the well was flowed for 12 hours. After four hours of clean-up the reported flow rate was 620stb/d on 1/2” choke, with BS&W at 10%. After 3 hours shut-in, the well was flowed for a further two hours on a 1” choke with the initial flowrate of 1,000stb/d falling to 500stb/d with a water cut of between 20 and 30%.

Fluid samples from the Phase 1 tests were contaminated rendering their analyses suspect. RPS understands that subsequent oil analyses have shown the gravity of the oil in Miran to be in the region of 15º API.

After clean up DST #3, #4 and #5 were re-perforated and re-tested. DST #3R and DST #4R flowed water. DST #5R was re-perforated and acidised over the interval +166m to -64m TVDSS. Water flowed on test on DST #5R-A. Heritage interpreted this to be due to a failure of the bridge plug during acidisation which allowed water to flow from the open perforations down-hole. After isolating the lower perforations with a bridge plug with a top at 3.6m bmsl DST #5R-B zone the well flowed 98% oil. A rate of 3,640 stb/day of 15º API oil was obtained after two further acid jobs and use of a larger pump.

5.4.2 Miran West-2 Drill Stem Tests Twelve DSTs were run in Miran West-2 (Table 5-2) with limited success. Of the 12 tests, 4 of them were in the Upper Cretaceous, 2 in the Lower Cretaceous, 5 in the Jurassic with the remaining test in the Triassic formation.

In the Upper Cretaceous, DST #2 in the Uppermost Qamchuqa flowed water. DST #1 in the Shiranish did not flow as the formation was tight. DST #1 was a barefoot test with the packer at 655 mMD. Some 160 stb acid was squeezed in to the formation, a jet pump was set but only production water, mud, CO2 and a trace of oil were recovered with CO2 progressively decreasing downhole. DST #3 and #4 in the Shiranish Fm resulted in no flow after acidisation and were assumed to be tight. DST #2 was acidised and resulted in cumulative water production of 2,000 Bbls at a rate of 5,000 Bwpd.

Of the two Lower Cretaceous test, DST #12 flowed acid with a trace of gas, whilst DST #11 flowed filtrate with gas and a trace of condensate. Both were considered tight gas-bearing with associated H2S and CO2.

The Jurassic tests were the most successful with three of them, DSTs #7, #8 and #9 flowing gas and condensate at recordable levels. DST #9 flowed gas at a rate of 26 MMscf/d with approximately 450 bpd of 60.8˚ API condensate, DST #8 flowed gas at a rate of 25 MMscf/d with 50 bpd of 54.3˚ API condensate whilst DST #7 was very similar with a gas rate of 26 MMscf/d and 50 bpd of 50˚ API condensate. Again, on average, 6% of H2S and 5% of CO2 were present in all the three DST tests. In DST#9, however, the measured H2S was as high as 10%. The remaining test in this zone, DST #10, flowed filtrate and was deemed tight gas-bearing.


ECV 1851 42 July 2012

The only test in the Triassic formation was DST #6 which flowed water at a rate of 2,000 Bwpd.

Depth (m MD)

Depth (m, TVDSS) Stratigraphy Comment

DST #1 714 – 1,000 -202 (amsl) – 84 Shiranish / Kometan Acidised, no flow. Tight

DST #4 1,002 – 1,099 85 – 183 Qamchuqa Acidised, no flow. Tight

DST #3 1,101 – 1,210 185 – 294 Qamchuqa Acidised, no flow. Tight

DST #2 1,335 – 1,424 419 – 508 L. Balambo / Sarmord Acidised, flowed water, H2S

DST #12 1,846 – 2,117.5 928 – 1,198 L. Balambo / Sarmord

Acidised, produced trace of gas with H2S & CO2

DST #11 2,117.5 – 2,220 1,198 – 1,301 L. Balambo / Sarmord / Chia Gara

Acidised, flowed filtrate with gas, ~0.18 MMscfd, with associated H2S and CO2.

DST #10 2,220 – 2,427 1,301 – 1,507 Chia Gara / Barsarin / Sargelu

Acidised, flowed post-acid filtrate, ~100 Bpd with associated H2S and CO2

DST #5 2,625 – 3,147 1,703 – 2,225 Alan / Mus / Butmah

Acidised, and aborted due to high H2S

DST #9 2,992 – 3,115 2,070 – 2,193 Butmah Acidised, flowed ~26 MMcfd, 450 Bpd of 60.8 ˚ API cond., ~80 Bwpd, H2S & CO2

DST #8 3,327 – 3,410 2,404 – 2,487 Butmah Acidised, flowed ~25 MMcfd, ~100 bpd of 54.3 ˚ API cond., ~200 Bwpd, H2S & CO2

DST #7 3,465 – 3,533 2,542 – 2,610 Butmah Acidised, flowed ~26 MMcfd, ~100 bpd of 47-52 ˚ API cond., ~200 Bwpd, H2S & CO2

DST #6 4,163 – 4,426 3,240 – 3,502 U..Kurra Chine Acidised, tested water at 2000 Bpd, with CO2


5.4.3 Miran West-3 Drill Stem Tests Four drill stem tests were conducted in Miran West-3 as described in Table 5-3. In summary, the tests show oil in the Upper Cretaceous, water below the Cretaceous oil, and gas in the Jurassic.

DST#1 produced 15°API oil at a maximum measured rate of 1,890 Bopd.

DST#2 produced water at approximately 2,400 Bwpd.

DST#3 failed to produce any hydrocarbons to surface over an 8 hour flow period. Acid stimulation pump rates and pump pressures indicated a tight formation. Analysis of the downhole pressure confirms the tight nature of the interval. Post-test, a small bubble of gas was circulated out.

DST#4 tested a reservoir interval above the main Jurassic reservoir. A flow of up to 17.5 MMscf/d of dry gas was measured. The reservoir interval tested is separate from the underlying main Jurassic gas bearing reservoir tested in the Miran West-2 well8.

8 During May 2012 a Heritage press release stated that testing of the main Jurassic reservoir in the Miran West-3 well resulted in a constrained flow of up to 22 MMscf/d of wet gas with a yield of 20 bbl/MMscf of 55°API condensate.


ECV 1851 43 July 2012

DST Depth (m MD)

Depth (m, TVDSS) Stratigraphy Comment

DST #1 732 – 876 -169.2 (amsl) - 29.9 (amsl)

Tanjero / Shiranish (Upper Cretaceous)

A stable rate of around 630 Bopd, 15 API oil (GOR < 10 scf/bbl)

DST #2 1,032 – 1,076 121.9 – 164.6 Kometan (Upper Cretaceous) Flowed 2,400 Bwpd water

DST #3 2,012 – 2,270 1,064.7 – 1,304.8 Sarmord (Lower Cretaceous)

Tight, small bubbles of gas post test circulated out

DST #4 2,907 – 3,060 1,895.2 – 2,024.3 Adaiyah (Jurassic) Flowed gas, 17.5 MMscf/d


5.4.4 Contacts – Miran West RPS has looked at the petrophysical interpretation, DST fluids recovered and the pressure measurements in wells Miran West-1, -2 and -3. The petrophysical interpretation does not provide evidence of water contacts. The estimated contacts are mainly based on the test results as described below. These contact depths were used as guides in the REP calculation.

Oil-Water Contact DSTs 5R-B and 5R-C in Miran West-1 flowed oil. The base of the perforation interval of -36m TVDSS was taken as the oil down to (“ODT”) / P90 spill point input value. Similarly, DST#2 in Miran West-3 flowed water. The top of the perforation interval, i.e. -121.9m TVDSS can be considered as water up to (“WUT”) which was taken as the P10 spill point input value9.

Gas-Water Contact The pressure data from the DSTs of the Miran West-2 well were analysed. DST #2 which was a water test, coincided with the water gradient provided by the DSTs from Miran West-1. DST #6 in Miran West-2 was also a water test and although this was the only test in the Triassic, a water gradient similar to the Upper Cretaceous water gradient was assumed through this point. A gas gradient was generated from DSTs #7, #8 and #9. Although not so obvious, a similar gradient could also be inferred from the results of Miran West-1 DST #1 and Miran West-2 DSTs #10 and #11. In terms of contacts, the only information that the above provided was a gas down to depth of 3533m MD (-2611m TVDSS) in the Jurassic Butmah Fm, from DST #7. This value was used as a guide depth in REPTM calculations.

5.5 In-place Volumes RPS considers that Miran West contains Contingent Oil Resources in the U. Cretaceous (Shiranish) and Contingent Gas Resources in the L. Cretaceous (Sarmord) and Jurassic (Adaiyah and Butmah). In addition, Prospective Oil Resources are assigned to the U. Cretaceous (Tanjero) and Prospective Gas Resources to the Triassic (U. & L. Kurra Chine).

In addition, RPS assigns Prospective Oil Resources to the U. Cretaceous reservoirs and Prospective Gas Resources to Jurassic reservoirs in the Miran East and Miran South prospects.

RPS has taken a probabilistic approach for the volumetric estimations using Logicom’s REP™ stochastic modelling program.

Gross Rock Volume GRVs were calculated for each reservoir segment using an area v depth approach with spill points / contact ranges based on a combination of mapped structural closure and potential contacts based on pressure data. Reservoir thickness ranges were constrained by the well control.

Reservoir Quality

9 The pressure measurements in Miran West-1 and -3 include both oil and water points. The interpretation based on the oil and water gradients are however very sensitive due to the high density of the 15°API oil; as an example, one unit error in the API measurement causes 20 m error in the contact estimation. RPS has estimated oil water contacts by intersecting oil and water gradients drawn from different recorded DST pressure points. The range of values obtained are in good agreement with the ODT and WUT considered above.


ECV 1851 44 July 2012

RPS reviewed the inputs provided by Heritage for their volumetric calculations and the petrophysical analyses by Senergy on which they were based. RPS is of the opinion that the overall approach used by Senergy is sound, although it is possible that there may be a modest overestimation of hydrocarbon saturation in the matrix pore volume.

Drilling results from the Miran wells indicate that open fractures can be expected in all the carbonate reservoirs, but their distribution, frequency and hence quantification remains uncertain. RPS concurs with the Heritage approach of using a dual porosity model with fracture porosity between 0 and 1% used for all horizons. Matrix porosity ranges were varied by horizon based on the petrophysics and occasionally from observations of core porosity.

Open, hydrocarbon-filled fractures often have low water saturations. The Heritage estimates of between 2 and 10% were deemed reasonable and these values were used as the P90 and P10 REP inputs to define a normal distribution (clipped at 0%). Significantly higher Sw ranges were used for the matrix pore volume.

Hydrocarbons The hydrocarbons tested in the U. Cretaceous (Shiranish Fm) in Miran West-1 have a very low gas-oil ratio and consequently the formation volume factor (Boi) is very low. P90 / P10 values of 1.01 / 1.06 rb/stb were used by RPS for a normal distribution in REP.

For the gas reservoirs ranges for condensate / gas ratios and inert gases (H2S and CO2) were applied, based on the test results.

Recovery Factors Separate recovery factors were applied probabilistically to the matrix and fracture pore volumes. Relatively high recovery factors were applied to the in-place volumes held in the fractures, whereas only very low recovery factors were applied to the matrix pore volumes (see Section 5.5).

In-Place Volumes and Resources The Contingent and Prospective volumes assigned by RPS for the Miran West discovery are shown in Table 5-4. The Contingent Gas volumes assigned to the Lower Cretaceous and Jurassic reservoirs have been statistically consolidated in REPTM and it was these ranges that were carried forward for economic valuation. Similarly the Prospective Gas Resources, with their associated Chances of Geological Success, were consolidated and carried forward for economic valuation.


ECV 1851 45 July 2012

Table 5-4: Miran West - Hydrocarbons In-place and Resources (RPS)

The Prospective resources assigned to the Miran East and Miran South prospects are shown in Table 5-5 and Table 5-6 respectively.

Table 5-5: Miran East - Hydrocarbons in-place and Prospective Resources (RPS)

MIRAN WEST

P90 P50 P10 Mean 1C 2C 3C MeanJurassic ‐ Butmah Total 1788 4038 9489 5034 837 1894 4317 2305(Zone 2a) Matrix 372 1388 4843 2163 50 260 1020 438

Fracture 1416 2650 4647 2872 787 1634 3297 1867

Jurassic ‐ Adaiyah Total 736 1614 3187 1825 265 571 1099 639(Zone 2b) Matrix 355 1018 2342 1218 54 189 506 245

Fracture 382 596 845 607 210 382 593 395

L. Cretaceous ‐ Sarmord Total 1236 3057 6749 3615 197 477 1046 565(Zone 3) Matrix 994 2697 6236 3249 76 250 670 327

Fracture 242 359 513 366 121 227 375 238

Zones 2a, 2b & 3 Total 5835 9657 16086 10466 1879 3135 5581 3500Liquids (MMstb) 16 31 59 35

P90 P50 P10 Mean 1C 2C 3C MeanU. Cretaceous ‐ Shiranish Total 163 354 807 434 21 52 108 60(Zone 4) Matrix 76 238 681 322 3 12 44 19

Fracture 87 116 126 113 19 39 64 40

P90 P50 P10 Mean 1C 2C 3C MeanU. Cretaceous ‐ Tanjero Total 470 984 1798 1074 17 56 131 67 38

Matrix 0 0 0 0 0 0 0 0Fracture 470 984 1798 1074 17 56 131 67

P90 P50 P10 Mean P90 P50 P10 MeanTriassic ‐ U. Kurra Chine Total 45 198 565 262 17 77 221 102 41

Matrix 25 122 379 170 6 28 98 43Fracture 19 76 186 92 12 48 123 60

Triassic ‐ L. Kurra Chine Total 45 198 565 262 17 77 221 102 29Matrix 25 122 379 170 6 28 98 43Fracture 19 76 186 92 12 48 123 60

Triassic ‐ U&L Kurra Chine Total 54 242 683 318 21 94 268 124 58Liquids (MMstb) 0.2 1.3 4.4 1.9

GIIP (Bcf) Resources (Bcf)

STOIIP (MMstb) Resources (MMstb)

Prospective ‐ Gas

STOIIP (MMstb)

GIIP (Bcf)

Contingent ‐ Gas

Consolidation

Consolidation

Contingent ‐ Oil

Prospective ‐ Oil Resources (MMstb)

Resources (Bcf)

GPoS (%)

GPoS (%)

MIRAN EAST

P90 P50 P10 Mean P90 P50 P10 MeanJurassic ‐ Butmah Total 302 574 1049 637 142 272 467 292 34(Zone 2a) Matrix 48 197 588 272 7 37 125 55

Fracture 254 377 461 364 135 235 342 237

Jurassic ‐ Adayiah Total 147 259 429 277 58 106 173 112 42(Zone 2b) Matrix 53 135 272 151 7 25 61 31

Fracture 94 125 157 126 51 82 113 82

L. Cretaceous ‐ Sarmord Total 366 822 1643 921 58 128 254 145 23(Zone 3) Matrix 293 727 1524 836 22 68 166 84

Fracture 73 95 119 94 36 61 88 61

Zones 2a, 2b & 3 Total 209 625 1574 777 78 212 499 256 71Liquids (MMstb) 0.6 2.0 5.3 2.6

P90 P50 P10 Mean P90 P50 P10 MeanU. Cretaceous ‐ Shiranish Total 81 318 1229 541 11 44 169 74 58(Zone 4) Matrix 44 207 950 401 2 11 59 24

Fracture 38 111 278 140 9 34 111 50

Resources (Bcf)GIIP (Bcf)

Resources (MMstb)STOIIP (MMstb)

Prospective ‐ Gas

Consolidation

Prospective ‐ Oil

GPoS (%)

GPoS (%)


ECV 1851 46 July 2012

Table 5-6: Miran South - Hydrocarbons In-place and Prospective Resources (RPS)

A summary of the Contingent Resources and Prospective Resources volumes (excluding inerts) carried forward for the economic evaluation are shown in Table 5-7 and Table 5-8 respectively.

Contingent Resources

Gas (Bscf) Oil (MMstb)

Miran West 1C 2C 3C Mean 1C 2C 3C Mean

L. Cretaceous / Jurassic (Adaiyah / Butmah / Sarmord) 1,879 3,135 5,581 3,500 16 31 59 35

U. Cretaceous (Shiranish) --- --- --- --- 21 52 108 60

Table 5-7: Summary of Contingent Resources (RPS)

Prospective Resources

CoS (%) Gas (Bscf) Oil (MMstb)

Miran West P90 P50 P10 Mean P90 P50 P10 Mean

U. Cretaceous (Tanjero) --- --- --- --- 17 56 131 67 38

Triassic (U & L. Kurra Chine) 21 94 268 124 0.2 1.3 4.4 1.9 58

Miran East

L. Cretaceous / Jurassic (Adaiyah / Butmah / Sarmord) 78 212 499 256 0.6 2.0 5.3 2.6 71

U. Cretaceous (Shiranish) --- --- --- --- 11 44 169 74 58

Miran South

L. Cretaceous / Jurassic (Adaiyah / Butmah / Sarmord) 15 61 155 75 0.1 0.6 1.7 0.8 28

U. Cretaceous (Shiranish) --- --- --- --- 4.0 17 64 28 14

Table 5-8: Summary of Prospective Resources (RPS)

5.6 Reservoir Engineering RPS has produced the following production forecasts:

• Zone 4 Oil in Miran West – based on the Contingent Oil Resources proved in the Cretaceous formations in Miran West.

• Zone 4 Oil in Miran East – based on the Prospective Oil Resources in the Cretaceous formations in Miran East.

• Zone 4 Oil in Miran South – based on the Prospective Oil Resources in the Cretaceous formations in Miran South.

MIRAN SOUTH

P90 P50 P10 Mean P90 P50 P10 MeanJurassic ‐ Adayiah/Butmah Total 33 131 338 165 15 61 155 75 28(Zone 2) Matrix 8 42 169 71 1.3 7.8 35 14

Fracture 25 89 169 94 14 54 119 61Liquids (MMstb) 0.1 0.6 1.7 0.8

P90 P50 P10 Mean P90 P50 P10 MeanU. Cretaceous ‐ Shiranish Total 30 123 465 202 4.0 17 64 28 14(Zone 4) Matrix 16 79 360 149 0.6 4.0 22 9

Fracture 13 44 105 52 3.4 13 41 19

Resources (MMstb)STOIIP (MMstb)

GIIP (Bcf) Resources (Bcf)

GPoS (%)

Prospective ‐ Gas

Prospective ‐ Oil

GPoS (%)


ECV 1851 47 July 2012

• Tanjero Oil – based on the Prospective Oil Resources in the Upper Cretaceous formation in Miran West.

• Zone 2a, 2b and 3 Consolidated Gas in Miran West – based on the Contingent Gas Resources proved in the Jurassic and Lower Cretaceous formations in Miran West.

• Triassic Gas– based on the Prospective Gas Resources in the Triassic formation in Miran West.

• Zone 2a, 2b and 3 Consolidated Gas in Miran East – based on the Prospective Gas Resources in the Jurassic and Lower Cretaceous formations in Miran East.

• Zone 2a, 2b and 3 Consolidated Gas in Miran South – based on the Prospective Gas Resources in the Jurassic and Lower Cretaceous formations in Miran South.

5.6.1 Zone 4 Oil Recovery Factors and Resources Several tests conducted in Miran West-1 and 3 flowed oil in the Cretaceous. The oil density was measured at 15°API with a GOR of about 10 scf/stb. The current Heritage Field Development Plan is relying on the aquifer as the prevailing production drive, i.e., there is no plan for waterflooding. The aquifer support is, however, uncertain at this stage of field development. RPS therefore has considered a 1C-2C-3C recovery factor range of 15%-35%-55% for the oil in the fractures and a recovery factor range of 1%-5%-10% for the oil in the matrices.

Resources were calculated by applying the recovery factor range probabilistically and are given in Table 5-4 (21, 52 and 108 MMstb for the 1C-2C-3C cases). For the economic valuation, RPS made production forecasts for the Contingent Oil Resources in Miran West Zone 4. The oil production profiles are given in Table 5-9 and Figure 5-4.

Heritage’s proposed FDP, at the time of conducting this project included two phases; an Early Production Scheme (“EPS”) to start in 2014 using trucks for the transportation, followed by the full field development starting the export via pipelines in 2015. The Early Production Scheme has since been suppressed upon the advice from RPS and RPS has updated its forecast assuming that the full field production commencement date is 1st July 2016, i.e when all the facilities and pipelines are installed and operational.

The well plateau rates, resources per well, and number of wells are given in Table 5-10. The rates were estimated based on the test results. The drilling time is estimated to be about 30 days for Zone 4. Rig move, completion and hook-up are estimated at an additional total of 16 days for all cases.


ECV 1851 48 July 2012

Year Avg Yearly Oil Rate (stb/d)

1C 2C 3C

2016 4,000 9,000 16,200

2017 8,000 18,000 32,400

2018 8,000 18,000 32,400

2019 8,000 18,000 32,400

2020 7,600 18,000 32,400

2021 5,573 16,754 32,400

2022 4,050 11,044 32,400

2023 3,026 7,488 29,251

2024 2,315 5,411 16,315

2025 1,807 4,093 9,790

2026 1,434 3,205 6,527

2027 1,156 2,577 4,662

2028 944 2,117 3,497

2029 780 1,771 2,720

2030 651 1,503 2,176

2031 286 1,291 1,780

2032 0 1,121 1,483

2033 983 1,255

2034 869 1,076

2035 773 932

2036 356 816

2037 0 720

2038 640

2039 573

2040 515

2041 239

2042 0

Total (MMstb) 21.0 52.0 108.1

Table 5-9: Miran West Contingent Oil Production Profiles (100% Basis)

Producers Injectors for

Water Reinjection

Well Plateau Rate

(stb/d)

Resources per Well

(MMstb)

Well Life Time

(years)

1C 8 1 1,000 2.6 15

2C 9 1 2,000 5.8 20

3C 9 1 3,600 12.0 25

Table 5-10: Production Assumptions for Zone 4 Miran West Oil

RPS Ener

ECV 1851

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ECV 1851 50 July 2012


Low Mid High

2016 2,250 8,000 25,246

2017 4,500 16,000 51,100

2018 4,500 16,000 51,100

2019 4,500 16,000 51,100

2020 4,226 16,000 51,100

2021 2,895 14,717 51,100

2022 1,973 9,087 51,100

2023 1,400 5,862 46,072

2024 1,025 4,095 25,265

2025 771 3,023 14,956

2026 593 2,323 9,888

2027 465 1,841 7,022

2028 371 1,494 5,245

2029 300 1,238 4,067

2030 246 1,042 3,245

2031 107 889 2,650

2032 0 767 2,205

2033 669 1,863

2034 589 1,595

2035 522 1,381

2036 239 1,207

2037 0 1,064

2038 945

2039 845

2040 760

2041 356

2042 0

Total (MMstb) 11.0 44.0 168.9

Table 5-11: Miran East Prospective Oil Production Profiles (100% Basis)

Producers Well Plateau

Rate (stb/d)

Resources per Well

(MMstb)

Well Life Time

(years)

Low 5 900 2.2 15

Mid 8 2,000 5.5 20

High 14 3,650 12.1 25

Table 5-12: Production Assumptions for Zone 4 Miran East Oil


ECV 1851 51 July 2012

Figure 5-5: Miran East Prospective Oil Production Profiles (100% Basis)

5.6.3 Zone 4 Oil in Miran South No wells have been drilled in Miran South. RPS therefore has assumed the oil quality is similar to Miran West (15°API). The Miran West recovery factors were used for Miran South; a Low-Mid-High recovery factor range of 15%-35-55% for the oil in the fractures and a recovery factor range of 1%-5%-10% for the oil in the matrices.

Resources were calculated by applying the recovery factor range probabilistically and are given in Table 5-6 (4, 17 and 64 MMstb for the Low-Mid-High cases). For the economic valuation, RPS made production forecasts for the Prospective Oil Resources in Miran South Zone 4. The oil production profiles are given in Table 5-13 and Figure 5-6.

The well plateau rates, resources per well, and number of wells are given in Table 6-2. The estimated well plateau rates and resources per well parameters are considered to be lower than Miran West due to the smaller size of Miran South, and the well lives are considered to be shorter. The drilling time is estimated to be about 30 days for Zone 4. Rig move, completion and hook-up are estimated at an additional total of 16 days for all cases. It is assumed that the liquids will be sent to Miran West production unit for processing.

0

20

40

60

80

100

120

140

160

180

0

10

20

30

40

50

60

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

Cumulative Oil Prod

uctio

n (M

Mstb)

Oil Ra

te (M

stb/d)

Year

Low Rate Mid Rate High Rate

Low Cumulative Mid Cumulative High Cumulative


ECV 1851 52 July 2012


Low Mid High

2016 1,000 3,500 10,725

2017 2,000 7,000 21,450

2018 2,000 7,000 21,450

2019 1,882 7,000 21,450

2020 1,304 6,566 21,450

2021 898 4,464 21,450

2022 642 3,022 19,477

2023 474 2,132 11,209

2024 358 1,555 6,874

2025 277 1,165 4,646

2026 115 894 3,350

2027 0 699 2,530

2028 556 1,978

2029 449 1,589

2030 367 1,305

2031 159 1,090

2032 0 925

2033 794

2034 690

2035 604

2036 275

2037 0

Total (MMstb) 4.0 17.0 64.0

Table 5-13: Miran South Prospective Oil Production Profiles (100% Basis)

Producers Well Plateau

Rate (stb/d)

Resources per Well

(MMstb)

Well Life Time

(years)

Low 5 400 0.8 10

Mid 7 1,000 2.4 15

High 11 1,950 5.8 20

Table 5-14: Production Assumptions for Zone 4 Miran South Oil


ECV 1851 53 July 2012

Figure 5-6: Miran South Prospective Oil Production Profiles (100% Basis)

5.6.4 Tanjero Oil The prospective oil resources in the Tanjero formation in Miran West are expected to be too viscous for production via waterflooding or aquifer drive. The oil is estimated to be in the fractures only. RPS has considered a recovery factor range of 2%-6%-10% under steam-flooding.

Resources were calculated by applying the recovery factor range probabilistically and are given in Table 5-4 (17, 56 and 131 for the Low-Mid-High cases). For the economic valuation, RPS made production forecasts for the Prospective Oil Resources in Miran West Tanjero. The oil production profiles are given in Table 5-15 and Figure 5-7.

The well plateau rates, resources per well, and number of wells are given in Table 5-16. The drilling time is estimated to be about 30 days for Tanjero. Rig move, completion and hook-up are estimated at an additional total of 16 days for all cases. Tanjero production is assumed to be processed by its dedicated production unit.

0

10

20

30

40

50

60

70

0

5

10

15

20

25

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

Cumulative Oil Prod

uctio

n (M

Mstb)

Oil Ra

te (M

stb/d)

Year




ECV 1851 54 July 2012


Low Mid High

2016 2,400 6,400 14,400

2017 5,400 14,400 28,800

2018 5,400 14,400 28,800

2019 5,400 14,400 28,800

2020 5,400 14,400 28,800

2021 5,182 14,400 28,800

2022 3,961 14,400 28,800

2023 2,997 13,759 28,800

2024 2,348 10,231 28,800

2025 1,888 7,551 27,124

2026 1,552 5,802 19,097

2027 1,298 4,598 13,649

2028 1,102 3,733 10,242

2029 947 3,091 7,968

2030 823 2,602 6,376

2031 413 2,221 5,218

2032 - 1,917 4,349

2033 1,672 3,681

2034 1,471 3,155

2035 1,304 2,735

2036 664 2,393

2037 - 2,112

2038 1,877

2039 1,680

2040 1,512

2041 701

2042 -

Total (MMstb) 17.0 56.0 131.0

Table 5-15: Miran West Tanjero Prospective Oil Production Profiles (100% Basis)

Producers Steam Injectors

Well Plateau Rate

(stb/d)

Resources per Well

(MMstb)

Well Life Time

(years)

Low 18 18 300 0.9 10

Mid 18 18 800 3.1 15

High 18 18 1,600 7.3 20

Table 5-16: Production Assumptions for Miran West Tanjero


ECV 1851 55 July 2012

Figure 5-7: Miran West Tanjero Prospective Oil Production Profiles (100% Basis)

5.6.5 Zone 2a, 2b and 3 Consolidated Gas in Miran West Several of the DSTs in Miran West-2 and 3 in the Jurassic zones (Zones 2a and 2b) flowed gas with associated condensate. In the Lower Cretaceous zone (zone 3) the DSTs reported tight gas with little or no flow. The Jurassic gas was reported to contain high levels of Carbon Dioxide (CO2) and Hydrogen Sulphide (H2S); up to 6% and 11% respectively from the Miran West-2 tests.

RPS has estimated the range of recovery factors for the matrix and fracture systems to be 10-20-30% and 60-65-70% respectively for Zones 2a and 2b for the 1C-2C-3C cases. For Zone 3 the corresponding recovery factors were 5-10-15% for the matrix and 60-65-70% for the fractures due to lower matrix porosity. Contingent resources were generated by applying the recovery factor ranges probabilistically to each zone and then statistically consolidating the volumes as reported in Table 5-4 (1,879, 3,135 and 5,581 Bscf for the 1C-2C-3C cases).

The DSTs from Miran West-2 were used to estimate the CGR. Values of 5-10-15 bbl/MMscf for the 1C-2C-3C cases were assumed for both the Jurassic and Lower Cretaceous zones. These were applied probabilistically to generate the condensate resources.

Heritage’s proposed FDP at the time of conducting this project included two phases; an Early Production Scheme (“EPS”) to start in 2014 to sell 80 MMscf/d gas to the local market, followed by the full field development starting the export in 2015. The early production scheme has now been suppressed upon the advice from RPS and RPS has updated its forecast assuming that the full field production commencement date is 1st July 2016, i.e when all the facilities and pipelines are installed and operational.

A minimum of 10 years on plateau was used as the main forecast criterion. This resulted in a field plateau rate of 630 MMscf/d (including inerts). Resources per well were set at 50-85-120 bcf. The drilling time was estimated to be 50 days with an additional 16 days for rig move, completion and hook-up. The 1C-2C-3C gas resources production profiles are shown in Table 5-17 and illustrated in Figure 5-8.

The local gas sale is supposed to be 80 MMscf/d for 10 years. The remaining “net of inert” gas will be exported following the plant fuel consumptions and inefficiency losses.

0

20

40

60

80

100

120

140

0

5

10

15

20

25

30

35

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

Cumulative Oil Prod

uctio

n (M

Mstb)

Oil Ra

te (M

stb/d)

Year



RPS Ener

ECV 1851

rgy

Table 5-177: Miran West Conti

56

ingent Gas Production Profiles (10

Herita

00% Basis)

age – CPR

July 2012


ECV 1851 57 July 2012

Figure 5-8: Miran West Contingent Gas Resources Production Profiles (100% Basis)

In the above forecasts, the number of producers for the 1C-2C-3C cases were 45-45-55, four of which in each case being recompletions of Appraisal wells.

5.6.6 Triassic Gas in Miran West The only DST in the Triassic and Kurra Chine Formations was in well Miran West-2 and was a water test. As a result, analogue fields in the area were used to determine the parameters for the gas forecasts.

Recovery factors for the Triassic gas forecasts were set as 15-25-35% for the matrix and 60-65-70% for the fractures for the Low-Mid-High cases respectively in the two Triassic gas zones. The prospective resources were generated by applying the recovery factor ranges probabilistically to each zone and then statistically consolidating the volumes as reported in Table 5-4 (21, 94 and 268 Bscf for the Low-Mid-High cases).

For the condensate, a CGR range of 5-15-25 bbl/MMscf for the Low-Mid-High cases were assumed for both the Lower and Upper Kurra Chine zones. These were again applied probabilistically to generate the condensate prospective resources.

For the gas forecasts, a single phase development was assumed to commence in mid 2016. Maximum well rates of 12-41-50 MMscf/d and resources per well of 6-30-80 bcf were used for the Low-Mid-High cases respectively. Four wells were assumed for each case. The drilling time was estimated to be 60 days with an additional 16 days for rig move, completion and hook-up. The Low-Mid-High gas resources production profiles are shown in Table 5-18 and illustrated in Figure 5-9.

0

1000

2000

3000

4000

5000

6000

7000

0

100

200

300

400

500

600

700

Cumulative Gas Produ

ction (Bscf)

Gas Rate (M

Mscf/d)

1C Rate 2C Rate 3C Rate 1C Cumulative 2C Cumulative 3C Cumulative


ECV 1851 58 July 2012

Table 5-18: Miran West Prospective Gas Production Profiles (100% Basis)

Figure 5-9: Miran West Prospective Gas Production Profiles (100% Basis)

Low Mid High Low Mid High Low Mid High2016 6.0 20.5 24.9 5.0 17.1 21.4 47 237 3512017 10.5 41.0 50.0 8.7 34.3 42.9 83 474 7052018 8.8 40.0 50.0 7.3 33.5 42.9 70 463 7052019 7.4 34.2 50.0 6.2 28.6 42.9 59 396 7052020 6.2 28.7 49.9 5.2 24.0 42.8 49 332 7032021 5.2 24.2 50.0 4.3 20.2 42.9 41 279 7052022 4.4 20.3 50.0 3.6 17.0 42.9 35 235 7052023 3.7 17.0 50.0 3.1 14.2 42.9 29 197 7052024 3.1 14.3 49.9 2.6 11.9 42.8 24 165 7032025 2.6 12.0 50.0 2.2 10.0 42.9 21 139 7052026 2.2 10.1 50.0 1.8 8.4 42.9 17 117 7052027 1.8 8.5 50.0 1.5 7.1 42.9 14 98 7052028 1.5 7.1 45.5 1.3 5.9 39.1 12 82 6412029 1.3 6.0 38.5 1.1 5.0 33.0 10 69 5422030 1.1 5.0 32.4 0.9 4.2 27.8 9 58 4572031 0.9 4.2 27.3 0.8 3.5 23.5 7 49 3852032 0.8 3.5 23.0 0.6 3.0 19.7 6 41 3242033 0.6 3.0 19.4 0.5 2.5 16.7 5 34 2742034 0.5 2.5 16.4 0.4 2.1 14.0 4 29 2312035 0.5 2.1 13.8 0.4 1.8 11.8 4 24 1942036 0.2 1.8 11.6 0.2 1.5 9.9 2 20 1632037 0.0 1.5 9.8 0.0 1.2 8.4 0 17 1382038 0.6 8.3 0.5 7.1 7 1162039 0.0 7.0 0.0 6.0 0 982040 5.9 5.0 822041 4.9 4.2 702042 4.2 3.6 592043 3.5 3.0 492044 3.0 2.5 422045 2.5 2.1 352046 2.1 1.8 302047 1.8 1.5 252048 0.0 0.0 0

Total (Bcf,MMstb) 25 113 313 21 94 268 0.20 1.30 4.40

Year

Avg Yearly Gas Rate (MMscf/d) Avg Yearly Gas Rate (MMscf/d) Avg Yearly Condensate Rate (stb/d)Incuding Inerts Net of Inerts

0

50

100

150

200

250

300

350

0

10

20

30

40

50

60

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048


ction (Bscf)

Gas Rate (M

Mscf/d)

Low Rate Mid Rate High Rate Low Cumulative Mid Cumulative High Cumulative


ECV 1851 59 July 2012

5.6.7 Zone 2a, 2b and 3 Consolidated Gas in Miran East At the time of writing, the Lower Cretaceous and Jurassic zones (Zones 2a, 2b and 3) in Miran East were undrilled. However, it was assumed that these zones would contain gas with similar properties to that in Zones 2a, 2b and 3 in Miran West. Hence Miran West was used as an analogue for Miran East.

The range of recovery factors used for the matrix and fracture systems were 10-20-30% and 60-65-70% respectively for Zones 2a and 2b for the Low-Mid-High cases. For Zone 3 the corresponding recovery factors were 5-10-15% for the matrix and 60-65-70% for the fractures due to smaller matrix porosity. The prospective resources were generated by applying the recovery factor ranges probabilistically to each zone and then statistically consolidating the volumes as reported in Table 5-5 (78, 212 and 499 Bscf for the Low-Mid-High cases).

For the condensate, a CGR range of 5-10-15 bbl/MMscf for the Low-Mid-High cases were assumed for the lower Cretaceous and Jurassic zones. These were again applied probabilistically to generate the condensate prospective resources.

For the gas forecasts, a single phase development was assumed to commence in 2017. Maximum well rates of 34-50-50 MMscf/d and resources per well of 20-50-120 bcf were used for the Low-Mid-High cases respectively. Five wells were assumed for each case. The drilling time was estimated to be 50 days with an additional 16 days for rig move, completion and hook-up. The Low-Mid-High gas resources production profiles are shown in Table 5-19 and illustrated in Figure 5-10.


ECV 1851 60 July 2012

Table 5-19: Miran East Prospective Gas Production Profiles (100% Basis)

Low Mid High Low Mid High Low Mid High2016 16.9 24.9 24.9 14.0 20.9 21.4 108 197 2272017 33.9 50.0 50.0 28.1 41.8 42.9 216 395 4562018 33.3 50.0 50.0 27.6 41.8 42.9 213 395 4562019 28.7 50.0 50.0 23.8 41.8 42.9 183 395 4562020 24.0 49.9 49.9 19.9 41.7 42.8 153 394 4552021 20.2 50.0 50.0 16.8 41.8 42.9 129 395 4562022 16.9 50.0 50.0 14.1 41.8 42.9 108 395 4562023 14.2 50.0 50.0 11.8 41.8 42.9 91 395 4562024 11.9 49.7 49.9 9.9 41.6 42.8 76 392 4552025 10.0 44.3 50.0 8.3 37.0 42.9 64 350 4562026 8.4 37.2 50.0 7.0 31.1 42.9 54 294 4562027 7.0 31.3 50.0 5.8 26.2 42.9 45 247 4562028 5.9 26.3 49.9 4.9 22.0 42.8 38 207 4552029 5.0 22.1 50.0 4.1 18.5 42.9 32 175 4562030 4.2 18.6 50.0 3.5 15.6 42.9 27 147 4562031 3.5 15.6 50.0 2.9 13.1 42.9 22 123 4562032 2.9 13.1 49.9 2.4 11.0 42.8 19 103 4552033 2.5 11.1 50.0 2.0 9.2 42.9 16 87 4562034 2.1 9.3 50.0 1.7 7.8 42.9 13 73 4562035 1.7 7.8 50.0 1.4 6.5 42.9 11 62 4562036 1.4 6.6 49.9 1.2 5.5 42.8 9 52 4552037 1.2 5.5 50.0 1.0 4.6 42.9 8 44 4562038 0.6 4.6 50.0 0.5 3.9 42.9 4 37 4562039 0.0 3.9 50.0 0.0 3.3 42.9 0 31 4562040 3.3 49.9 2.7 42.8 26 4552041 2.8 50.0 2.3 42.9 22 4562042 2.3 50.0 1.9 42.9 18 4562043 2.0 45.4 1.6 39.0 15 4142044 1.4 37.9 1.2 32.5 11 3452045 0.0 31.7 0.0 27.2 0 2892046 26.5 22.7 2412047 22.1 19.0 2012048 18.4 15.8 1682049 15.4 13.2 1412050 12.9 11.0 1172051 10.8 9.2 982052 9.0 7.7 822053 7.5 6.4 682054 6.3 5.4 572055 5.2 4.5 482056 4.4 3.7 402057 3.7 3.1 332058 3.1 2.6 282059 2.5 2.2 232060 2.1 1.8 192061 1.8 1.5 162062 1.5 1.3 142063 0.0 0.0 0

Total (Bcf,MMstb) 94 253 582 78 212 499 0.60 2.00 5.30

Year



ECV 1851 61 July 2012

Figure 5-10: Miran East Prospective Gas Production Profiles (100% Basis)

5.6.8 Zone 2a, 2b and 3 Consolidated Gas in Miran South The prospect Miran South is undrilled to date and Miran West was used as an analogue.

Only Zone 2 was expected to contain gas and hence recovery factors for the matrix and fracture systems were set to 10-20-30% and 60-65-70% respectively for the Low-Mid-High cases. The prospective resources were generated by applying the recovery factor ranges probabilistically and are shown in Table 5-6 (15, 61 and 155 Bscf for the Low-Mid-High cases).

For the condensate, a CGR range of 5-10-15 bbl/MMscf was assumed for the Low-Mid-High cases. These were again applied probabilistically to generate the condensate resources.

For the gas forecasts, a single phase development was assumed to commence mid 2016. Maximum well rates of 9-26-50 MMscf/d and resources per well of 6-25-60 bcf were used for the Low-Mid-High cases respectively. Three wells were assumed for each case. The drilling time was estimated to be 50 days with an additional 16 days for rig move, completion and hook-up. The Low-Mid-High gas resources production profiles are shown in Table 5-20 and illustrated in Figure 5-11.

0

100

200

300

400

500

600

700

0

10

20

30

40

50

60

2015

2017

2019

2021

2023

2025

2027

2029

2031

2033

2035

2037

2039

2041

2043

2045

2047

2049

2051

2053

2055

2057

2059

2061

2063


ction (Bscf)

Gas Rate (M

Mscf/d)



ECV 1851 62 July 2012

Table 5-20: Miran South Prospective Gas Resources Production Profiles (100% Basis)

Figure 5-11: Miran South Prospective Gas Resources Production Profiles (100% Basis)

Low Mid High Low Mid High Low Mid High2016 4.3 13.0 24.9 3.6 10.8 21.4 24 107 2352017 7.5 26.0 50.0 6.3 21.8 42.9 42 214 4712018 6.3 25.4 50.0 5.2 21.2 42.9 35 209 4712019 5.3 21.8 50.0 4.4 18.3 42.9 29 180 4712020 4.4 18.4 48.8 3.7 15.4 41.8 25 151 4592021 3.7 15.6 42.3 3.1 13.0 36.3 21 128 3982022 3.1 13.2 36.0 2.6 11.0 30.9 17 108 3392023 2.6 11.1 30.6 2.2 9.3 26.3 15 91 2882024 2.2 9.4 26.0 1.8 7.8 22.3 12 77 2442025 1.9 7.9 22.1 1.5 6.6 19.0 10 65 2082026 1.6 6.7 18.8 1.3 5.6 16.2 9 55 1772027 1.3 5.7 16.0 1.1 4.7 13.7 7 47 1512028 1.1 4.8 13.6 0.9 4.0 11.7 6 39 1282029 0.9 4.0 11.6 0.8 3.4 9.9 5 33 1092030 0.8 3.4 9.9 0.6 2.9 8.5 4 28 932031 0.6 2.9 8.4 0.5 2.4 7.2 4 24 792032 0.5 2.4 7.1 0.4 2.0 6.1 3 20 672033 0.5 2.1 6.1 0.4 1.7 5.2 3 17 572034 0.4 1.7 5.2 0.3 1.5 4.4 2 14 492035 0.3 1.5 4.4 0.3 1.2 3.8 2 12 412036 0.1 1.2 3.7 0.1 1.0 3.2 1 10 352037 0.0 1.0 3.2 0.0 0.9 2.7 0 9 302038 0.5 2.7 0.4 2.3 4 252039 0.0 2.3 0.0 2.0 0 222040 1.0 0.9 102041 0.0 0.0 0

Total (Bcf,MMstb) 18 73 181 15 61 155 0.1 0.6 1.7

Year


0

20

40

60

80

100

120

140

160

180

200

0

10

20

30

40

50

60

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040


ction (Bscf)

Gas Rate (M

Mscf/d)



ECV 1851 63 July 2012

5.7 Facilities and Cost Estimates

5.7.1 Contingent Resources – Miran West A new FDP has been generated by Heritage in conjunction with Petrofac. In the P50 case, Miran West has contingent resources of 2.95 Tscf of sales gas and 31 MMstb of Condensate in the Jurassic, with 52 MMstb of oil in the Upper Cretaceous. The valuation is based on a development scenario of exporting processed sales quality gas to the Turkish border for sale in Turkey and potential onward transportation to Europe. It is understood that the Turkish Gas Company are planning to construct a gas transmission pipeline to the Kurdistan border. Oil and condensate will be transported to Taq Taq where it will tie-in to the planned Kurdish International Crude Export (KICE) pipeline.

Miran gas is sour with approximately 10% H2S content and will potentially produce 1,800te of sulphur a day and 650,000te per annum. Heritage are planning to construct a railway system to Kirkuk, 80km away, where the main Iraqi rail system operates, and propose that the buyer of the sulphur collects the pelletised product at the Miran site FOB using its own rolling stock and locomotives. RPS is not in a position to opine on whether such sulphur export is feasible and whether markets for the export of such volumes exist. Heritage advises the Sulphur is currently being sold from the Kirkuk field at US$180/tonne FOB.

As a part of the FDP above Heritage are planning to produce processed gas to local markets. Approximately 80 MMscfd of gas will be delivered to local cement factories and possibly to a power station in Sulaymaniyah.

5.7.1.1 Capital Expenditure Capex has been taken from the Petrofac costs estimates in the FDP. RPS has reviewed all costs associated with the FFD and considers them to be reasonable. Because of the difference in resource estimates, RPS has made changes to the relevant items in the cost estimates using the ‘six-tenths’10 rule, used widely in the oil industry. The costs of the main plant with a processing capacity of 630MMscfd raw gas has been reduced from US$1,832MM to US$1,698MM as a consequence. These costs include Pig Launchers/Receivers, Camp and Power systems. Costs for the 320km export pipeline to Turkey have been taken from the FDP at $484MM. Wellhead, facilities and gathering system are adjusted to the number of wells in each scenario and infrastructure costs are taken directly from the FDP estimates. More than half of the Capex is associated with the sour gas processing and it is noted that a 30% contingency has been included by the design engineers.

The sulphur export rail system estimate, from Miran to Kirkuk is estimated at US$133MM. This estimate has again been provided by the design engineers. RPS concurs.

RPS has applied a general 5% Indirect Cost to cater for owner’s costs, insurances, etc.

Overall Capex for the full field development is circa US$2.73bn.

Inevitable delays in the sanction process have pushed the start date back to mid-2013. After considerable consultation with Petrofac and Heritage, RPS considers that first hydrocarbons could be achieved by Mid-2016.

Drilling to date has been proved to be lengthy due to the complex geology and hard formations and the presence of Hydrogen Sulphide in large percentages. The Miran West-1 exploration well, drilled in 2008/9, cost US$36MM with the follow up appraisal well Miran West-2 which tested gas costing US$67MM following a redesign of the well whilst drilling. The next five appraisal wells are forecasted to cost an average US$40MM each and it is proposed to re-complete most of these wells as producers. The 2012 drilling Budget stands at about US$95MM and US$60MM for 2013.

10 The Rule of Six-tenths

Approximate costs can be obtained if the cost of a similar item of different size or capacity is known using the equation;

CB=CA(SB/SA)0.6

Where CB = the approximate cost of equipment having size SB, CA = is the known cost of equipment having corresponding size SA (same units as SB),and SB/SA is the ratio known as the size factor, dimensionless.


ECV 1851 64 July 2012

Some of the appraisal wells will be re-completed at an estimated cost of $10MM. The average cost for a new gas production well will be US$25MM and US$12MM for an oil well.

In the P50 case the full field development requires a further 45 gas wells, nine oil wells, and one water injector.

Total Drillex, including appraisal wells, is estimated at US$1.45bn.

5.7.1.2 Operating Costs OPEX costs are taken from the Heritage/Petrofac FDP. It is recognised that the main plant is slightly smaller than the FDP but RPS has a higher well count and therefore the Petrofac estimated opex is considered to be reasonable.

The FFD Opex, for the mean case, is US$105 MM for the fixed field portion together with a variable element of US$0.50/bbl or US$23 MM/annum. Workover costs are included every three years at US$10 MM.

5.7.1.3 Abandonment Costs Abandonment costs vary according to plant size and well count. Plant removal and reinstatement is applied at 7% of the Facilities Capex and well abandonment at US$0.50/well. For the RPS P50 case this results in a provision of US$226 MM.

5.7.2 Prospective Resources Three further Prospects are included in the evaluation as follows:

• Miran East with 44MMstb and 212Bscf Prospective Resources (P50)

• Miran West with 56MMstb and 94Bscf PR (P50)

• Miran South with 17MMstb and 61Bscf PR (P50)

All three prospects are seen as future tie-backs to the main Miran Central Production Facilities (CPF). For these evaluations, RPS has increased the processing capacity to 680MMscfd and associated costs in terms of Capex and Opex.

Miran East is located about 7km away from the CPF. Capex for Miran East is estimated at about US$130MM to gather and tie-in and will require 5 Gas wells, 8 Oil wells and 1 Water injector to deplete the prospect. Costs for drilling are put at US$250MM. Opex is estimated at US$12MM/annum including fixed and variable.

Miran West is located about 5km away and Capex for this prospect is estimated at US$150MM. The prospect will require more wells and hence higher gathering costs.

4 Gas wells, 18 Oil wells, and 18 Water Injectors are required for the development of the field at a cost of US$1.0bn. Annual Opex is estimated at US$22MM for this large tie-in.

Miran South is 37km from the CPF but has very small potential resources. Capex is estimated at US$96MM and will require 3 Gas wells, 7 Oil wells, and 1 Water injector at a cost of US$185MM. Fixed and variable Opex is about US$16MM/annum for this prospect.


ECV 1851 65 July 2012

6. ECONOMICS

6.1 Valuation Assumptions

6.1.1 General The effective date of this report is 31st March 2012 and this has been used as the discount date for the valuation. All values are post-tax and have been expressed over a range of discount rates. An annual inflation rate of 2% has been assumed and is applied to both costs and revenues.

6.1.2 Oil Prices The valuation has been based on the RPS long term forecast for Brent (long term price of US$95/stb in REAL 2012$ from 2015 onwards) as shown in Table 6-1 and Figure 6-1. A Low Price Case ($80/stb in REAL 2012$) and High Price Case ($110/stb in REAL 2012$) are also shown in the Table in Money of the Day (MOD) and have been used for price sensitivity purposes.

Low Price Case (US$/stb, MOD)

Base Price Case (US$/stb, MOD)

High Price Case (US$/stb, MOD)

2012 (9 months) 80.00 120.00 110.0011

2013 81.60 112.50 112.20

2014 83.23 105.30 114.44

2015 84.90 100.81 116.73

2016 86.59 102.83 119.07

2017 88.33 104.89 121.45

2018 90.09 106.99 123.88

2019 91.89 109.13 126.36

2020 93.73 111.31 128.88

2021 95.61 113.53 131.46

2022 97.52 115.80 134.09

2023 99.47 118.12 136.77

2024 101.46 120.48 139.51

2025 onwards + 2% p.a. + 2% p.a. + 2% p.a.

Table 6-1: RPS Forecast Price Cases

11

The RPS base price in the short term takes into account market opinion including the forward curve, but from 2015 we estimate a $95/bbl constant real price which we currently believe is a reasonable long-term price for valuing projects. Upside and downside price ranges test the economics at $80/bbl and $110/bbl real, which we apply from 2012 for simplicity, rather than 2015. This means the high price is below the base for a couple of years at the start but overall it is well above the base price. All resources are based only on the base price; the high and low case are used for sensitivity purposes only.

RPS Ener

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ECV 1851 67 July 2012

6.2.2 Contingent and Prospective Resources Contingent Resources have been assigned to Miran West: oil in the Cretaceous formation and gas in the Jurassic and Lower Cretaceous formations. The (1C, 2C and 3C) contingent resources of Miran West were evaluated using a spreadsheet-based cash flow model. This model contains a forecast of future production, prices and costs and honours the applicable contract terms to provide entitlement resources net to Heritage.

There are Prospective Oil Resources in Miran East, South and Tanjero in the Cretaceous formations. The 1C, 2C and 3C for the Miran West Contingent Oil Resources have been combined to give an expected value or ENPV. The P90, P50 and P10 Prospective Oil Resources per reservoir have then been consolidated with the Contingent Resources to produce an expected value for the combined Contingent and Prospective Resource volume. The expected value of the Prospective Oil Resources per reservoir has been derived from the difference between the expected value of the Contingent and Prospective Resources combined and the expected value of the Contingent Resource alone.

Prospective gas resources have been assigned to Miran West, East and South. The P90, P50 and P10 Prospective Gas Resources have been valued incrementally to the Contingent Gas Resources in the same way as the oil prospective resources were derived from the difference between the expected value of the Contingent and Prospective Resources combined and the expected value of the Contingent Resource alone.

6.3 NIGERIA – OML30

6.3.1 Fiscal Regime and Contract Terms RPS has modelled Heritage’s working interest in the OML 30 licence based on the following assumptions.

Heritage has informed us it is purchasing the 45% interest of the SPDC venture in OML 30 as part of a consortium, Shoreline Natural Resources Limited (hereafter, “SNRL”), which Heritage informs us consists of Heritage and a local partner, Shoreline Power (hereafter, “Shoreline”). The other 55% will be owned by NPDC.We have used – without independently confirming -- Heritage’s explanation of how Heritage’s net share of entitlement volumes, of working interest volumes, and of net cashflow (NCF; the basis for NPV) from the OML 30 license will vary as a function of the Net Profit Interest (NPI) of Shoreline.

This explanation is as follows. Before considering any exercise by Shoreline of an option to obtain a 30% interest in SNRL (discussed below), Shoreline’s NPI would evolve in three stages:

• Stage 1: before SNRL repays a US$550 mm loan from Standard Bank, which Heritage expects to be disbursed to SNRL in August 2012, Shoreline’s NPI would be 2.5% (i.e. 2.5% of SNRL’s 45% WI in OML 30). Heritage assumes the loan will have an annual interest rate of 9.5%, and will be repayable over 60 months. Heritage’s NPI would be 100.0% - 2.5% = 97.5%.

• Stage 2: after Stage 1, but before Stage 3 (see below), Shoreline’s NPI would be 5.0%. Heritage’s NPI would be 100.0% - 5.0% = 95.0%.

• Stage 3: after Stage 1, and after Heritage’s NPI share of (SNRL net cashflow – loan repayments) reaches US$1 billion, Shoreline’s NPI would be 10.0%. Heritage’s NPI would be 100.0% - 10.0% = 90.0%.

Key outcomes for Heritage are calculated as summarised in Table 6-3 below.


ECV 1851 68 July 2012

Calculation of key outcomes

Index Item Calculation

A SNRL (consortium) Net Cashflow (NCF) =45% * OML 30 total license NCF

B SNRL loan repayments Calculated as described above

C SNRL NCF, net of loan repayments = a – b

D Shoreline percentage Net Profit Interest (NPI) Calculated as described above

E Shoreline NCF = c * d

F Shoreline entitlement production = e / received oil price

G SNRL entitlement production = 45% * OML 30 total license production, net of royalty volumes

H Heritage entitlement production = g – f

I SNRL Working Interest (WI) production = g

J Shoreline WI production = d * i

K Heritage WI production = i - j

L Heritage NCF (basis for Heritage NPV) = a - e

Table 6-3: Methodology for calculating key outcomes relevant to OML 30

Note from the above that we have not deducted loan repayments in calculating Heritage’s NCF (Item L). Heritage says that a consideration within the Shoreline Shareholder Agreement is the Shoreline Power 30% purchase Option. To the end of 2012, SP can elect to acquire a 30% interest in Shoreline Natural Resources Limited. In that case the Heritage Net interest would be reduced by 30%, or Heritage’s net Interest would be 70% of that calculated in the preceding paragraph. We have not modelled this scenario.

The licence is due to expire in 2019. However, we assume, based on our general experience in licence valuations, that the government will renew the licence. In our assessment the licence expiry date is assumed to equal either the economic limit or 2049 whichever is the sooner for each case considered (see below).

6.3.1.1 Fiscal Terms not related to Income Tax Fiscal terms other than income tax include:

• a royalty levied at a rate of 20%

• an Education Tax, levied as 2% * (revenue - royalty - Opex)

• the “NDDC” levy, levied as 3% * (total Capex + total Opex)

• an annual licence rental payable at the rate of MOD US$ 1.1 mm

6.3.1.2 Fiscal Terms related to Income Tax The Education Tax, NDDC levy and annual rental are tax deductible.

Intangible Capex is expensed for tax purposes in the year incurred.

Tangible Capex is depreciated for tax purposes on a straight line basis, with a depreciable asset’s useful life being 5 years, and with 1% of initial book value being kept on the books thereafter. RPS has assumed the following tangible / intangible split of Capex:


ECV 1851 69 July 2012

Tangible Intangible

Exploration Seismic, G&G and Other Costs 50% 50%

Exploration Drilling 50% 50%

Appraisal Drilling 50% 50%

Facilities 90% 10%

Development Drilling 30% 70%

Pipelines 50% 50%

Table 6-4: Capex Split

Heritage, citing guidance from advisors PWC, says that it is also entitled to depreciate a portion of the purchase price it paid for its working interest in the OML 30 licence. Heritage says this depreciable portion is equal MOD US$ 58.5 mm. RPS has assumed this to be the case in our valuation, although RPS has not independently confirmed this to be the case.

In addition to tax allowances arising from depreciation charges, a Petroleum Investment Allowance permits a deduction from annual taxable income. This deduction is equal to 5 % of the value of annual tangible Capex.

Income tax losses may be carried forward to future periods until amortised.

Income Tax Rates Our Base Case Scenario assumes that current Nigerian income tax rates for petroleum production apply. The rates are 65.75% for the five tax years beginning 2012, and 85% thereafter.

RPS has also run an Alternative Tax Scenario at Heritage’s request, which uses different tax rates, based on forward-looking advice Heritage has received from advisors regarding a proposed Petroleum Industry Bill, which has not yet become law. The rates used in this scenario are 65.75% for the five tax years beginning 2012, and

• 70% thereafter, if SNRL’s working interest share of production is less than 50,000 Bopd

• 80% thereafter, if SNRL’s working interest share of production is greater than or equal to 50,000 Bopd

The results of the Alternative Tax Scenario are presented in Table 6-6.

6.3.2 Price Assumptions RPS has used Heritage’s assumption that the OML 30 realised crude price has a 3.2% premium to Brent, based on the historic premium of 3.2% to Brent at which Forcados Light has traded in between January 2007 and the end of March 2012. The prices are summarised in Table 6-5 below.


ECV 1851 70 July 2012

Brent Crude (RPS Base Case)

Real 2012 $ / stb

Brent Crude (RPS Base Case) MOD

$ / stb

OML 30 Realised

price (Assumes

3.2% premium to Brent)

MOD $ / stb

2-4Q 2012 120.43 120.43 124.31

2013 110.29 112.50 116.12

2014 101.21 105.30 108.69

2015 95.00 100.81 104.06

2016 95.00 102.83 106.14

2017 95.00 104.89 108.26

2018 95.00 106.99 110.43

2019 95.00 109.13 112.64

2020 95.00 111.31 114.89

2021 95.00 113.53 117.19

2022 95.00 115.80 119.53

2023 95.00 118.12 121.92

2024 95.00 120.48 124.36

2025 95.00 122.89 126.85

2026 95.00 125.35 129.38

2027 95.00 127.86 131.97

2028 95.00 130.41 134.61

2029 95.00 133.02 137.30

2030 95.00 135.68 140.05

Table 6-5: Assumed Oil prices for Brent Crude and OML30

6.3.3 Economic Limit The licence is assumed to reach its economic limit, i.e. is assumed to no longer be economically viable when the cumulative value of its undiscounted gross operating cashflow ceases to increase. Gross operating cashflow for this purpose is defined as 100% working interest field revenue less royalty, cash Opex, and taxes and levies other than income tax (discussed above).

6.3.4 Valuation Summary

Discount Rate Economic Limit

Post-Tax Net Present Value (US$ Million, MOD)

0.0% 5.0% 7.5% 10.0% 15.0%




Table 6-6: OML30 Post-Tax Valuation (Net Heritage Share)


ECV 1851 71 July 2012

Economic



0% 5.0% 7.5% 10.0% 15.0%




Table 6-7: OML30 Post-Tax Valuation (Net Heritage Share), Heritage alternative Income Tax Scenario





Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty






Table 6-8: OML30 Reserves Summary





Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty






Table 6-9: OML30 Reserves Summary, Heritage alternative Income Tax Scenario

Forecasts of production and cashflows for OML30 assuming both Tax Scenarios are shown in Appendix D.


ECV 1851 72 July 2012

6.3.5 Sensitivity to Oil Price Sensitivity of the NPV10 of the future net revenue in OML30 to changes in oil price is shown in Table 6-13.

Price Case

Net Present Value10 of Future Net Revenue

(US$ Million, MOD)

1P 2P 3P

Low Price ($80 REAL) 1,330 2,482 3,608

Base Price 1,699 3,089 4,470

High Price ($110 REAL) 1,953 3,558 5,145

Table 6-10: Sensitivity of OML30 NPV10 to Oil Price

6.4 Russia – Zapadno Chumpasskoye

6.4.1 Fiscal Regime and Contract Terms The Zapadno Chumpasskoye licence is due to expire in September 2024. The main commercial terms are:

Crude Oil Export Duty

$4 + 60% x (Actual price – US$25)

VAT 18 per cent. on domestic sales

Mineral Extraction Tax (MET)

Oil a. MET = 446 x Cp x Cw x Cz

where Cp = (P – 15) x R / 261

P = average quarterly price of Urals Blend (US$/stb)

R = average quarterly exchange rate for US$/Rouble

b. MET = 470 x Cp from 01.01.2013

c. Cw = 3.8 – 3.5 x N/V

where V = initially extractable oil reserves. Cw applies when depletion of reserves is greater than 80%.

Cw reduces MET when cumulative production > 80% of the ultimate recovery

d. Cz = (0.125 x V) + 0.375. Cz applies to fields with reserves (A+B+C1+C2) less than 5 MM tonnes and the reserves depletion level is less than 5%

Tax base – Revenue less VAT, excise tax, custom duties, transportation costs and insurance costs

Property Tax 2.2 per cent.

Tax base – Cumulative CAPEX (drilling & facilities) less depreciation

Income / Profits Tax 20.0% A reduction in Profits Tax, of 3% to 4%, is available


ECV 1851 73 July 2012

when annual investments are significant.

(- 4%) If CAPEX amount of a fiscal period increase a half of CAPEX amount for two preceding fiscal periods.

(- 3%) if the amount of cash saved after the given tax rate does not exceed 10% of CAPEX amount of a fiscal period(n).

Tax base – Revenue less OPEX, depreciation, interest, exchange rate losses and losses on re-evaluation.

Depreciation:

Facilities: 7-10 years

Drilling: 10-15 years

Pipelines: 20-25 years

Loss carry forward – 10 years

6.4.2 Price Assumptions Heritage has assumed that the gross field production will be split between export (via Black Sea) and domestic sales. This has been assumed to be 5% / 95% in 2012, 10% / 90% in 2013 and then 40% / 60% from 2014 onwards respectively. The export price has been based on the Urals (Mediterranean) price. This has been derived from the Brent forecast using a relationship based on an analysis of historical prices (Figure 6-2). A 2% discount to Brent has been assumed for the valuation. The domestic price was assumed to be 49% of the Urals price.

Figure 6-2: Plot of Brent vs. URALS (Mediterranean) – 2010-2012

6.4.3 Transportation Costs Estimates of the transportation costs for export via the Transneft pipeline system were provided by Heritage. A figure of 1500 Roubles per tonne (US$5.00/stb) was used for export costs. Domestic sales are assumed to be at the Transneft custody point and as such any transportation costs are built into the domestic price.

$60

$70

$80

$90

$100

$110

$120

$130

$60 $80 $100 $120 $140

URAL

S (Med

iterranean, US$/bbl)

Brent (US$/bbl)


ECV 1851 74 July 2012

6.4.4 Exchange Rate and Tax Losses A constant exchange rate of 30 Roubles to the US US$ was assumed for the valuation. The total tax loss carry forward (net Heritage share) at 31/03/2010 of US$24.625 MM was included in the valuation as a deduction against future profits tax liabilities. In addition, US$17.2 MM (net Heritage share) was included as the undepreciated sunk costs. These sums were provided by Heritage.

6.4.5 Valuation Summary Although the licence expiry date is 2024, the value and reserves have been reported up to their economic limit on the assumption that the licence will be extended to allow full economic recovery of all the reserves. The valuation includes the cost of abandonment of the wells and all facilities, which has been estimated to be US$29.3 MM, US$36.3 MM and US$53.5 MM (in 2012 US$) for the 1P, 2P and 3P cases, respectively. The post-tax valuation of the net Heritage share is given in Table 6-11.

Discount Rate Economic Limit

Post-Tax Net Present Value (US$ Million, MOD)

0.0% 5.0% 7.5% 10.0% 15.0%

Proved Reserves (1P) 2032 192 109 78 52 15

Proved plus Probable Reserves (2P) 2036 887 546 429 336 206

Proved plus Probable plus Possible Reserves (3P) 2036 2,912 1,630 1,253 976 610

Table 6-11: Zapadno Chumpasskoye Post-Tax Valuation (Net Heritage Share)

Zapadno Chumpasskoye reserves are summarised in Table 6-12, below.





Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

Gross of Royalty

Net of Royalty

(MMstb) (MMstb) (MMstb) (MMstb) (MMstb) (MMstb) Proved Reserves (1P) 24 24 23 23 23 23 Proved plus Probable Reserves (2P) 69 69 65 65 65 65

Proved plus Probable plus Possible Reserves (3P) 172 172 163 163 163 163

Notes 1. The Chumpasskoye fiscal regime does not include a royalty. 2. Under the terms of the Chumpasskoye licence the Net Working Interest volumes and Net Entitlement

volumes are the same.

Table 6-12: Zapadno Chumpasskoye Reserves Summary

6.4.6 Sensitivity to Oil Price Sensitivity of the NPV10 of the future net revenue in Zapadno Chumpasskoye to changes in oil price is shown in Table 6-13.


ECV 1851 75 July 2012

Price Case

Net Present Value10 of Future Net Revenue

(US$ Million, MOD)

1P 2P 3P

Low Price ($80 REAL) 16 244 772

Base Price 52 336 976

High Price ($110 REAL) 82 417 1,161

Table 6-13: Sensitivity of Zapadno Chumpasskoye NPV10 to Oil Price

6.5 Kurdistan – Miran Block

6.5.1 Fiscal Regime and Contract Terms The Miran Block was signed in October 2007. The exploration period is 5 years in duration and is subdivided into an initial sub-period of 3 years with the option of a second sub-period of 2 years. The development period lasts for an initial 20 years and can be extended for an additional 5 years.

RPS confirms that it has had full access to the final, signed copy of PSC and amendments under the terms of such agreements and that the commercial terms therein have been built into our economic models. The agreements and amendments are on the KRG website. The RPS valuation honours fully these commercial terms.

The commercial structure of the PSC, is in our opinion, very similar to standard PSCs with the Contractor’s entitlement revenue comprising of Cost Oil (defined as a maximum percentage of the net revenue) and Profit Oil (shared between the Contractor and the Government based on a R factor, the R factor being defined as the ratio of cumulative revenue divided by cumulative costs). A royalty payment is due under the contract on gross production and net revenue is defined as the gross revenue less royalty. As is normal, the Contractor’s Income Tax liability is paid by the Government out of its share of Profit Oil. The Government may participate in any future development at a level of up to 25% at the point when commerciality is declared, but is not required to make any repayment to the Contractor for costs incurred up to that point.

RPS has not taken into account in its cash flows the US$35 MM payment for removal of the obligation to build a refinery that was in the original PSC terms.

6.5.2 Price Assumptions Hydrocarbon liquids produced and sold from the Miran licence are forecast to comprise a mix of heavy (15 API) crude oil and light (60 API) condensate. Heritage says that in order to access export pipelines, the Contractor must ensure that the blend of its hydrocarbon liquids is at least 30 ˚ API.

In cases where the blend of the Contractor’s hydrocarbon liquids is below 30 ˚ API, Heritage says the Contractor intends to purchase from third parties crude oil of API 42 ˚ to blend with the Contractor’s own volumes, in sufficient quantities to raise the overall blend to 30 ˚ API. We estimate that such feedstock will cost the Contractor Real 2012 US$116/bbl (including a US$2/bbl handling charge) to be escalated by 2.0% annual inflation. Payments made by the Contractor for this feedstock are assumed not to be cost recoverable.

RPS has followed Heritage’s guidance in assuming that the Contractor’s netback price for the liquids blend will equal (97% of the Brent crude price) less transport tariffs of Real 2012 US$2.00 / bbl. Heritage assumes this will be the case even if the blend of its own production – i.e. excluding any feedstock – exceeds 30 ˚ API.

For future gas sales sold at the Turkish border into Turkey/Europe RPS has assumed a 2012 gas price of US$12/Mscf based on recent sales prices. We expect the gas price to move in line with our assumed Brent price movements. On advice from Heritage, RPS has assumed a sales price of 4.5 to 5.0 US$/mcf for domestically sold gas.

6.5.3 Sunk Costs The unrecovered costs at 31/12/2012 for the Miran Block are US$190.24 MM of which Heritage’s 75% interest is US$142.72MM. This sum was provided by Heritage.


ECV 1851 76 July 2012

6.5.4 Post Tax Contractor Share

6.5.4.1 Contingent Resources The Contingent Oil and Gas Resources in Miran have been evaluated separately on a standalone basis and the 1C, 2C and 3C entitlement resources attributable to the contractor under the PSC from cost recovery and profit share represent the contractor share, of which Heritage holds a 75% interest. The gross contractor share over time as a percentage of gross revenue from contingent resources are shown in Appendix C.

A summary of the gross Contingent Resources and the net working interest Contingent Resources in Heritage’s Properties is given in Table 6-14 and Table 6-15.

Gross Field Heritage Net WI Heritage Net Entitlement


Net of Royalty 1


Net of Royalty 1,2,3 Net of Royalty

(MMstb) (MMstb) (MMstb) (MMstb) (MMstb) 1C Resources 37 33 21 19 8.3 2C Resources 83 75 47 42 15 3C Resources 167 150 94 84 25 Mean Resources4 94 85 53 48 16 Notes 1. Values net of royalty are the most economically meaningful, as they reflect the deduction of royalty

volumes to which the Government is entitled. Values gross of royalty are shown at Heritage's request. 2. Net Working Interest volumes are notional values obtained by multiplying the corresponding Gross

Field values by Heritage's working interest. They are not economically meaningful, however, as they do not reflect Heritage's actual entitlement under the terms of the Miran PSC. Net Entitlement volumes are economically meaningful as they do represent the actual volumes to which Heritage is entitled. They are by definition net of royalty.



Table 6-14: Summary of Oil and Condensate Contingent Resources for Miran Field as of 31st March 2012


Net Entitlement


Net of Royalty 1



Net of Royalty

(Bscf) (Bscf) (Bscf) (Bscf) (Bscf)

1C Resources 1,760 1,584 990 891 491 2C Resources 2,929 2,637 1,648 1,483 669 3C Resources 5,087 4,578 2,861 2,575 940 Mean Resources4 3,226 2,903 1,815 1,633 697 Notes 1. Values net of royalty are the most economically meaningful, as they reflect the deduction of royalty





Table 6-15: Summary of Gas Contingent Resources for Miran Field as of 31st March 2012


ECV 1851 77 July 2012

6.5.4.2 Prospective Resources Appendix C shows the Gross Contractor Share of Revenue after Tax for Miran Prospective Resources. A higher gas capacity is assumed than in the Contingent Resource cases. Prospective Resource figures are shown combined with the high gas capacity Contingent Resource case. Tables of prices and costs are provided for each case. It is noted that the liquid netback price reflects the impact of the purchases of blending feed stock. Heritage’s net working interest is calculated assuming state back-in upon commerciality which reduces Heritage net working interest from 75% to 56.25%.


ECV 1851 78 July 2012

APPENDIX A: GLOSSARY OF TECHNICAL TERMS

1P Proved

2P Proved plus Probable

3P Proved plus Probable plus Possible

AAPG American Association of Petroleum Geologists

API American Petroleum Institute

B Billion

Barg gauge pressure in Bar

Bbls Barrels

Bopd barrels of oil per day

Bo(g)i initial formation volume factor for oil (or gas)

Bscf billion standard cubic feet

Btu British Thermal Units

Bwpd barrels of water per day

(i/n)Cn (isomeric or normal) hydrocarbon of the general form CnH2n+2

C1 C1H4, methane

C3 C3H8, propane

C4 C4H10, butane

C7(+) C7H16, heptane (plus, meaning heptane and all heavier fractions))

CGR Condensate: Gas Ratio

CO2 carbon dioxide

CVD Constant Volume Depletion (a laboratory experiment)

DST drill stem test

Entitlement Volumes the volumes of oil and/or gas which a Contractor receives under the terms of a PSA

EoS Equation of State

FBHP flowing bottom hole pressure

FFD Full Field Development

Ft Feet

FVF Formation Volume Factor (also: Boi)

FWHP flowing well head pressure

G&A General & Administrative

GIIP Gas Initially In-place

GPoS Geological Probability of Success

GOC Gas-oil contact


ECV 1851 79 July 2012

GOR Gas: Oil Ratio

GRV gross rock volume

H2S hydrogen sulphide

LPG

Liquefied Petroleum Gas – in this context means either Butane or Propane or both

k(e) (effective) permeability

Kg Kilogram

Km Kilometre

M Metres

M Thousand

MD measured depth

mD permeability in milli-Darcies

MM Million

MBbls thousand barrels

MMBtu/d millions of British Thermal Units per day

MMBwpd million barrels of water per day

MMscfd or MMscf/d millions of standard cubic feet per day

MMstb million stock tank barrels

Money of the Day calculated allowing for the effect of inflation

MPa Mega Pascal

N2 Nitrogen

N:G Net to gross ratio

NIOC National Iranian Oil Company

OWC oil-water contact

PI Productivity Index (stb/d/psi)

p(b/r) (bubble point or reservoir) pressure

PSC / PSA Production Sharing Contract / Production Sharing Agreement

psi(a/g) pounds per square inch (absolute/gauge)

PTA Pressure transient analysis

PVT Pressure, Volume & Temperature

RF Recovery Factor

Rsi Solution GOR

Rw Water resistivity

S Skin, a measure of damage derived from well test analysis

Scf standard cubic feet measured at 14.7 pounds per square inch and 60° F

SPE Society of Petroleum Engineers


ECV 1851 80 July 2012

STOIIP Stock Tank Oil Initially In-place

stb Stock Tank Barrel

Sw Water Saturation

TD Total Depth

Tr Reservoir temperature

TVD True vertical depth

TVDSS true vertical depth (sub-sea)

URR Ultimate recoverable reserves (before economic cut-off)

VCL Volume of clay

VRR Voidage replacement ratio

VSH Volume of shale

WHFP Wellhead Flowing Pressure

Working Interest Share (of reserves) calculated by multiplying the Gross estimate by the Contractor’s Working Interest in a Production Sharing Contract

WPC World Petroleum Congress

Ώm Ohm-metre

ω Omega, a measure of fracture storage

λ Lambda, a measure of matrix-fracture flow

ρo. Oil density

µo Oil viscosity

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ECV 1851 82 July 2012

plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).

DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.

PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage.

Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.

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 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 subclassified based on project maturity and/or characterized by their economic status.

UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.

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.

UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Estimated Ultimate Recovery (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).

1.2 Project-Based Resources Evaluations The resources evaluation process consists of identifying a recovery project, or projects, associated with a petroleum accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of those in-place quantities that can be recovered by each project, and classifying the project(s) based on its maturity status or chance of commerciality.

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wells and rvoirs, or

ontractual of each

nses, and erty may property

esources h project. ocess. A cremental ssociated t which a ld be an

arate and umulation

e defined coverable

program involved stages of In-place forecast

bility of a me period ic, legal, arized as


ECV 1851 84 July 2012

forecast costs and product prices, the underlying influences include, but are not limited to, market conditions, transportation and processing infrastructure, fiscal terms, and taxes.

The resource quantities being estimated are those volumes producible from a project as measured according to delivery specifications at the point of sale or custody transfer. The cumulative production from the evaluation date forward to cessation of production is the remaining recoverable quantity. The sum of the associated annual net cash flows yields the estimated future net revenue. When the cash flows are discounted according to a defined discount rate and time period, the summation of the discounted cash flows is termed net present value (NPV) of the project.


ECV 1851 85 July 2012

APPENDIX C: CONTRACTOR SHARE OF REVENUE AND COSTS FOR CONTINGENT RESOURCES AND PROSPECTIVE RESOURCES


ECV 1851 86 July 2012


ECV 1851 87 July 2012


ECV 1851 88 July 2012

RPS Ener

ECV 1851

rgy

89

Heritaage – CPR

July 2012


ECV 1851 90 July 2012


ECV 1851 91 July 2012


ECV 1851 92 July 2012


ECV 1851 93 July 2012


ECV 1851 94 July 2012


ECV 1851 95 July 2012


ECV 1851 96 July 2012


ECV 1851 97 July 2012


ECV 1851 98 July 2012


ECV 1851 99 July 2012


ECV 1851 100 July 2012


ECV 1851 101 July 2012


ECV 1851 102 July 2012


ECV 1851 103 July 2012


ECV 1851 104 July 2012


ECV 1851 105 July 2012

APPENDIX D: OML 30 FORECASTS (FROM 1 APRIL 2012) OF PRODUCTION AND CASHFLOWS

Notes: 1) SNRL is a consortium with an assumed 45% working interest in the OML 42 license. SNRL consists of Shoreline Power (SP) and Heritage Oil & Gas (HOG). 2) SNRL's working interest is assumed to take effect starting 1 August 2012. 3) The allocation of SNRL working interest cashflows between SP and HOG is determined by the loan agreement discussed in the Economics section of this report.


ECV 1851 106 July 2012

100% working interest

basis

SP share

Production, gross of royalty


Received oil price

Revenue, gross of royalty Royalty

Levies / taxes other than on

income Opex Capex Aband. Costs

Cashflow before

income tax Income tax

Cashflow after

income tax

Cashflow after income

tax

Cashflow after

income tax

Discount factor

(@10%)

Cashflow after

income tax discounted

at 10% Period mm bbl mm bbl MOD $ / bbl MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm x.xQ2-4 2012 7.40 1.85 124.31 229.96 45.99 4.10 14.62 - 5.95 159.29 102.59 56.69 - 56.69 0.9496 53.84

2013 16.50 7.43 116.12 862.20 172.44 16.71 42.63 66.33 10.71 553.39 389.52 163.87 0.60 163.26 0.8877 144.93 2014 22.03 9.91 108.69 1,077.40 215.48 20.80 50.26 85.32 10.71 694.83 463.03 231.80 2.33 229.47 0.8070 185.19 2015 28.78 12.95 104.06 1,347.52 269.50 27.08 64.18 146.13 10.71 829.92 549.52 280.40 3.54 276.85 0.7337 203.12 2016 37.07 16.68 106.14 1,770.53 354.11 36.21 76.26 220.65 10.71 1,072.60 715.81 356.79 5.45 351.33 0.6668 234.27 2017 49.19 22.13 108.26 2,396.30 479.26 47.78 92.75 267.32 10.71 1,498.47 1,293.23 205.25 4.99 200.25 0.6062 121.39 2018 55.40 24.93 110.43 2,752.97 550.59 53.00 102.53 247.81 10.71 1,788.31 1,529.91 258.40 12.92 245.48 0.5511 135.28 2019 62.27 28.02 112.64 3,156.29 631.26 59.81 113.92 255.68 10.71 2,084.91 1,780.55 304.36 21.50 282.86 0.5010 141.71 2020 57.56 25.90 114.89 2,975.78 595.16 54.43 110.07 173.99 10.71 2,031.42 1,709.84 321.57 32.16 289.42 0.4553 131.78 2021 43.64 19.64 117.19 2,301.54 460.31 40.45 95.34 72.60 10.71 1,622.12 1,340.64 281.49 28.15 253.34 0.4139 104.86 2022 30.70 13.81 119.53 1,651.10 330.22 29.27 80.69 51.69 10.71 1,148.52 943.60 204.92 20.49 184.42 0.3763 69.40 2023 29.61 13.32 121.92 1,624.31 324.86 28.81 81.35 50.36 10.71 1,128.21 935.42 192.79 19.28 173.51 0.3421 59.36 2024 23.63 10.63 124.36 1,322.15 264.43 23.94 74.61 51.36 10.71 897.10 749.65 147.45 14.75 132.71 0.3109 41.26 2025 9.84 4.43 126.85 561.91 112.38 10.57 56.53 17.46 10.71 354.25 289.14 65.11 6.51 58.60 0.2826 16.56 2026 8.82 3.97 129.38 513.80 102.76 9.28 56.22 - 10.71 334.83 273.99 60.84 6.08 54.76 0.2569 14.07 2027 8.09 3.64 131.97 480.40 96.08 8.74 56.26 - 10.71 308.60 254.94 53.66 5.37 48.30 0.2336 11.28 2028 5.83 2.62 134.61 352.91 70.58 6.68 54.25 - 10.71 210.68 174.42 36.27 3.63 32.64 0.2123 6.93 2029 5.53 2.49 137.30 341.39 68.28 6.51 54.92 - 10.71 200.97 168.76 32.22 3.22 28.99 0.1930 5.60 2030 5.26 2.37 140.05 331.33 66.27 6.35 55.54 - 10.71 192.46 163.19 29.27 2.93 26.34 0.1755 4.62 2031 4.79 2.15 142.85 307.66 61.53 5.98 55.87 - 10.71 173.57 147.54 26.04 2.60 23.43 0.1595 3.74 2032 4.04 1.82 145.71 264.79 52.96 5.29 55.77 - 10.71 140.06 119.05 21.01 2.10 18.91 0.1450 2.74 2033 3.30 1.48 148.62 220.50 44.10 4.57 55.14 - 10.71 105.97 90.08 15.90 1.59 14.31 0.1318 1.89 2034 3.16 1.42 151.59 215.55 43.11 4.50 55.73 - 10.71 101.50 86.28 15.23 1.52 13.70 0.1198 1.64 2035 3.05 1.37 154.63 211.96 42.39 4.45 56.67 - 10.71 97.73 83.07 14.66 1.47 13.19 0.1089 1.44 2036 2.10 0.95 157.72 149.27 29.85 3.44 55.95 - 10.71 49.31 41.91 7.40 0.74 6.66 0.0990 0.66 2037 2.01 0.91 160.87 145.82 29.16 3.40 56.93 - 10.71 45.61 38.77 6.84 0.68 6.16 0.0900 0.55 2038 1.47 0.66 164.09 108.49 21.70 2.80 56.93 - 10.71 16.35 13.89 2.45 0.25 2.21 0.0818 0.18 2039 1.41 0.64 167.37 106.35 21.27 2.78 57.98 - 10.71 13.61 11.57 2.04 0.20 1.84 0.0744 0.14 2040 1.36 0.61 170.72 104.29 20.86 2.75 59.05 - 10.71 10.91 9.27 1.64 0.16 1.47 0.0676 0.10 2041 1.30 0.59 174.13 102.13 20.43 2.73 59.67 - 10.71 8.59 7.31 1.29 0.13 1.16 0.0614 0.07 2042 1.26 0.57 177.62 100.38 20.08 2.71 60.78 - 10.71 6.10 5.18 0.91 0.09 0.82 0.0559 0.05 2043 1.21 0.54 181.17 98.71 19.74 2.69 61.92 - 10.71 3.64 3.09 0.55 0.05 0.49 0.0508 0.02 2044 1.17 0.53 184.79 97.11 19.42 2.68 63.09 - 10.71 1.21 1.03 0.18 0.02 0.16 0.0462 0.01 2045 1.13 0.51 188.49 95.58 19.12 2.67 64.28 - 10.71 (1.20) - (1.20) (0.12) (1.08) 0.0420 (0.05) 2046 1.09 0.49 192.26 94.13 18.83 2.64 64.18 - 10.71 (2.23) - (2.23) (0.22) (2.01) 0.0381 (0.08) 2047 - - 196.10 - - - - - - - - - - - 0.0347 -

Total 540.96 241.95 28,472.52 5,694.50 546.60 2,272.89 1,706.71 370.22 17,881.60 14,485.76 3,395.84 205.18 3,190.66 NPV --> 1,698.54

OML 30 -- Proved case -- forecast (from 1 April 2012) of production and cashflows

Scenario: Income tax

rates as per existing law

SNRL 45% working interest basis HOG share


ECV 1851 107 July 2012


basis

SP share



Received oil price




Cashflow before


Cashflow after

income tax


tax

Cashflow after

income tax

Discount factor

(@10%)

Cashflow after


at 10% Period mm bbl mm bbl MOD $ / bbl MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm x.xQ2-4 2012 9.00 2.25 124.31 279.64 55.93 4.91 15.68 - 5.82 197.31 127.59 69.72 0.30 69.42 0.9496 65.92

2013 21.57 9.70 116.12 1,126.87 225.37 20.99 47.46 66.33 10.47 756.26 522.91 233.35 2.37 230.98 0.8877 205.05 2014 29.63 13.33 108.69 1,449.33 289.87 27.31 58.23 101.33 10.47 962.12 646.82 315.30 4.42 310.88 0.8070 250.89 2015 40.88 18.40 104.06 1,914.22 382.84 36.45 79.79 150.84 10.47 1,253.83 828.72 425.11 7.16 417.95 0.7337 306.64 2016 55.09 24.79 106.14 2,631.25 526.25 51.07 99.51 249.44 10.47 1,694.50 1,129.39 565.11 10.66 554.45 0.6668 369.71 2017 77.34 34.80 108.26 3,768.05 753.61 70.04 128.07 265.92 10.47 2,539.93 2,172.22 367.72 27.03 340.69 0.6062 206.52 2018 95.96 43.18 110.43 4,768.41 953.68 85.87 153.49 251.38 10.47 3,313.52 2,823.53 489.99 49.00 440.99 0.5511 243.02 2019 112.03 50.41 112.64 5,678.33 1,135.67 100.78 176.42 255.68 10.47 3,999.30 3,403.46 595.84 59.58 536.26 0.5010 268.65 2020 109.14 49.11 114.89 5,642.33 1,128.47 97.05 177.05 150.27 10.47 4,079.02 3,442.34 636.68 63.67 573.01 0.4553 260.90 2021 102.22 46.00 117.19 5,390.57 1,078.11 90.65 172.35 72.60 10.47 3,966.38 3,333.16 633.22 63.32 569.90 0.4139 235.89 2022 84.38 37.97 119.53 4,538.90 907.78 76.13 153.29 49.37 10.47 3,341.86 2,807.19 534.67 53.47 481.20 0.3763 181.07 2023 71.37 32.12 121.92 3,915.52 783.10 66.06 140.22 50.36 10.47 2,865.31 2,413.28 452.04 45.20 406.83 0.3421 139.17 2024 60.64 27.29 124.36 3,393.44 678.69 57.61 127.79 51.36 10.47 2,467.52 2,086.07 381.45 38.14 343.30 0.3109 106.74 2025 26.58 11.96 126.85 1,517.12 303.42 26.13 83.62 17.46 10.47 1,076.01 903.54 172.47 17.25 155.23 0.2826 43.87 2026 24.50 11.03 129.38 1,426.73 285.35 24.15 82.35 - 10.47 1,024.41 860.49 163.92 16.39 147.53 0.2569 37.91 2027 22.66 10.20 131.97 1,345.48 269.10 22.83 81.03 - 10.47 962.05 810.53 151.52 15.15 136.37 0.2336 31.85 2028 18.10 8.15 134.61 1,096.48 219.30 18.80 75.68 - 10.47 772.24 651.74 120.50 12.05 108.45 0.2123 23.02 2029 17.29 7.78 137.30 1,068.00 213.60 18.34 76.04 - 10.47 749.54 635.04 114.50 11.45 103.05 0.1930 19.89 2030 15.73 7.08 140.05 991.13 198.23 17.11 75.32 - 10.47 690.01 586.11 103.90 10.39 93.51 0.1755 16.41 2031 15.30 6.89 142.85 983.59 196.72 16.99 75.91 - 10.47 683.50 580.97 102.52 10.25 92.27 0.1595 14.72 2032 14.66 6.60 145.71 961.00 192.20 16.64 76.47 - 10.47 665.22 565.44 99.78 9.98 89.81 0.1450 13.02 2033 13.93 6.27 148.62 931.64 186.33 16.17 76.59 - 10.47 642.09 545.77 96.31 9.63 86.68 0.1318 11.42 2034 11.17 5.03 151.59 762.32 152.46 13.43 73.60 - 10.47 512.35 435.50 76.85 7.69 69.17 0.1198 8.29 2035 9.59 4.31 154.63 666.98 133.40 11.89 72.12 - 10.47 439.10 373.24 65.87 6.59 59.28 0.1089 6.46 2036 8.93 4.02 157.72 633.74 126.75 11.36 72.50 - 10.47 412.66 350.76 61.90 6.19 55.71 0.0990 5.51 2037 5.48 2.46 160.87 396.38 79.28 7.51 67.67 - 10.47 231.45 196.73 34.72 3.47 31.25 0.0900 2.81 2038 4.44 2.00 164.09 327.80 65.56 6.41 67.27 - 10.47 178.08 151.37 26.71 2.67 24.04 0.0818 1.97 2039 4.32 1.94 167.37 325.48 65.10 6.39 68.31 - 10.47 175.22 148.93 26.28 2.63 23.65 0.0744 1.76 2040 4.21 1.89 170.72 323.42 64.68 6.36 68.55 - 10.47 173.36 147.36 26.00 2.60 23.40 0.0676 1.58 2041 4.10 1.85 174.13 321.61 64.32 6.34 69.74 - 10.47 170.73 145.12 25.61 2.56 23.05 0.0614 1.42 2042 3.94 1.77 177.62 315.06 63.01 6.24 70.85 - 10.47 164.49 139.81 24.67 2.47 22.21 0.0559 1.24 2043 3.85 1.73 181.17 313.78 62.76 6.24 72.10 - 10.47 162.21 137.88 24.33 2.43 21.90 0.0508 1.11 2044 3.76 1.69 184.79 312.67 62.53 6.23 73.38 - 10.47 160.05 136.04 24.01 2.40 21.61 0.0462 1.00 2045 3.68 1.65 188.49 311.73 62.35 6.23 74.70 - 10.47 157.98 134.29 23.70 2.37 21.33 0.0420 0.89 2046 3.59 1.62 192.26 310.94 62.19 6.23 76.04 - 10.47 156.01 132.61 23.40 2.34 21.06 0.0381 0.80 2047 2.99 1.34 196.10 263.72 52.74 5.48 76.07 - 10.47 118.96 101.11 17.84 1.78 16.06 0.0347 0.56 2048 2.93 1.32 200.03 263.31 52.66 5.48 77.47 - 10.47 117.22 99.63 17.58 1.76 15.82 0.0315 0.50 2049 2.86 1.29 204.03 263.00 52.60 5.49 78.90 - 10.47 115.54 98.21 17.33 1.73 15.60 0.0287 0.45 2050 - - 208.11 - - - - - - - - - - - 0.0260 -

Total 1,117.82 501.22 60,929.96 12,185.99 1,079.36 3,391.63 1,732.35 393.28 42,147.35 34,804.91 7,342.44 588.55 6,753.89 NPV --> 3,088.63

OML 30 -- Proved + Probable case -- forecast (from 1 April 2012) of production and cashflows





ECV 1851 108 July 2012


basis

SP share



Received oil price




Cashflow before


Cashflow after

income tax


tax

Cashflow after

income tax

Discount factor

(@10%)

Cashflow after



2013 27.29 12.28 116.12 1,425.99 285.20 25.84 53.51 66.33 10.47 984.64 673.07 311.57 4.32 307.25 0.8877 272.76 2014 37.47 16.86 108.69 1,832.65 366.53 33.93 67.93 114.53 10.47 1,239.26 835.68 403.58 6.62 396.95 0.8070 320.36 2015 51.59 23.22 104.06 2,415.84 483.17 44.45 91.34 146.13 10.47 1,640.29 1,078.88 561.41 10.57 550.84 0.7337 404.14 2016 72.22 32.50 106.14 3,449.31 689.86 64.45 117.63 252.88 10.47 2,314.02 1,537.45 776.57 15.95 760.63 0.6668 507.19 2017 104.83 47.17 108.26 5,107.25 1,021.45 92.02 158.32 274.33 10.47 3,550.66 3,034.98 515.68 43.48 472.20 0.6062 286.24 2018 128.25 57.71 110.43 6,372.86 1,274.57 111.88 190.08 250.67 10.47 4,535.18 3,858.37 676.81 67.68 609.13 0.5511 335.68 2019 156.70 70.52 112.64 7,942.74 1,588.55 137.67 228.51 260.06 10.47 5,717.49 4,864.87 852.62 85.26 767.36 0.5010 384.43 2020 151.33 68.10 114.89 7,823.69 1,564.74 132.45 227.12 150.27 10.47 5,738.64 4,850.97 887.67 88.77 798.90 0.4553 363.75 2021 142.76 64.24 117.19 7,528.30 1,505.66 125.35 222.27 72.60 10.47 5,591.95 4,712.81 879.14 87.91 791.23 0.4139 327.51 2022 126.26 56.82 119.53 6,791.58 1,358.32 112.71 206.49 49.37 10.47 5,054.22 4,261.56 792.66 79.27 713.39 0.3763 268.45 2023 111.33 50.10 121.92 6,107.95 1,221.59 101.65 191.31 50.36 10.47 4,532.57 3,829.83 702.75 70.27 632.47 0.3421 216.36 2024 95.31 42.89 124.36 5,333.94 1,066.79 89.12 174.14 51.36 10.47 3,942.05 3,339.12 602.93 60.29 542.64 0.3109 168.71 2025 57.06 25.68 126.85 3,257.03 651.41 54.39 126.10 17.46 10.47 2,397.19 2,026.54 370.65 37.07 333.59 0.2826 94.28 2026 53.19 23.93 129.38 3,096.63 619.33 51.27 122.47 - 10.47 2,293.09 1,938.87 354.23 35.42 318.80 0.2569 81.92 2027 47.17 21.23 131.97 2,801.33 560.27 46.48 116.46 - 10.47 2,067.65 1,750.29 317.36 31.74 285.62 0.2336 66.72 2028 38.04 17.12 134.61 2,304.51 460.90 38.41 104.62 - 10.47 1,690.10 1,431.92 258.18 25.82 232.36 0.2123 49.33 2029 34.08 15.34 137.30 2,105.90 421.18 35.20 100.73 - 10.47 1,538.33 1,305.51 232.82 23.28 209.54 0.1930 40.44 2030 28.48 12.81 140.05 1,794.73 358.95 30.16 94.54 - 10.47 1,300.62 1,105.12 195.49 19.55 175.94 0.1755 30.87 2031 27.70 12.46 142.85 1,780.61 356.12 29.94 95.29 - 10.47 1,288.79 1,095.47 193.32 19.33 173.99 0.1595 27.75 2032 26.97 12.14 145.71 1,768.66 353.73 29.75 96.02 - 10.47 1,278.69 1,086.88 191.80 19.18 172.62 0.1450 25.02 2033 24.51 11.03 148.62 1,639.00 327.80 27.66 94.16 - 10.47 1,178.91 1,002.07 176.84 17.68 159.15 0.1318 20.97 2034 20.99 9.44 151.59 1,431.76 286.35 24.30 89.91 - 10.47 1,020.72 867.61 153.11 15.31 137.80 0.1198 16.51 2035 20.50 9.23 154.63 1,426.76 285.35 24.23 90.84 - 10.47 1,015.86 863.48 152.38 15.24 137.14 0.1089 14.94 2036 17.29 7.78 157.72 1,226.80 245.36 21.00 87.32 - 10.47 862.66 733.26 129.40 12.94 116.46 0.0990 11.53 2037 16.53 7.44 160.87 1,196.66 239.33 20.52 87.82 - 10.47 838.52 712.74 125.78 12.58 113.20 0.0900 10.19 2038 14.86 6.68 164.09 1,096.92 219.38 18.91 86.74 - 10.47 761.41 647.20 114.21 11.42 102.79 0.0818 8.41 2039 14.54 6.54 167.37 1,095.30 219.06 18.90 87.72 - 10.47 759.16 645.28 113.87 11.39 102.49 0.0744 7.62 2040 12.40 5.58 170.72 952.53 190.51 16.59 85.23 - 10.47 649.73 552.27 97.46 9.75 87.71 0.0676 5.93 2041 11.93 5.37 174.13 934.75 186.95 16.30 85.38 - 10.47 635.64 540.30 95.35 9.53 85.81 0.0614 5.27 2042 11.49 5.17 177.62 918.66 183.73 16.05 85.93 - 10.47 622.48 529.10 93.37 9.34 84.03 0.0559 4.69 2043 6.79 3.06 181.17 553.49 110.70 10.14 78.85 - 10.47 343.33 291.83 51.50 5.15 46.35 0.0508 2.35 2044 6.66 3.00 184.79 553.62 110.72 10.15 80.19 - 10.47 342.09 290.77 51.31 5.13 46.18 0.0462 2.13 2045 6.53 2.94 188.49 553.60 110.72 10.17 81.42 - 10.47 340.82 289.70 51.12 5.11 46.01 0.0420 1.93 2046 6.21 2.79 192.26 536.91 107.38 9.91 82.42 - 10.47 326.73 277.72 49.01 4.90 44.11 0.0381 1.68 2047 6.10 2.74 196.10 537.97 107.59 9.94 83.72 - 10.47 326.25 277.31 48.94 4.89 44.04 0.0347 1.53 2048 5.99 2.70 200.03 539.23 107.85 9.97 85.18 - 10.47 325.75 276.89 48.86 4.89 43.98 0.0315 1.39 2049 5.89 2.65 204.03 540.68 108.14 10.01 86.68 - 10.47 325.37 276.57 48.81 4.88 43.93 0.0287 1.26 2050 - - 208.11 - - - - - - - - - - - 0.0260 -

Total 1,738.02 779.95 97,111.70 19,422.34 1,667.68 4,261.06 1,756.33 393.28 69,611.01 57,848.07 11,762.94 992.59 10,770.35 NPV --> 4,469.71

OML 30 -- Proved + Probable + Possible case -- forecast (from 1 April 2012) of production and cashflows





ECV 1851 109 July 2012


basis

SP share



Received oil price




Cashflow before


Cashflow after

income tax


tax

Cashflow after

income tax

Discount factor

(@10%)

Cashflow after


at 10% Period mm bbl mm bbl MOD $ / bbl MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm MOD $ mm x.xQ2-4 2012 7.40 1.85 124.31 229.96 45.99 4.10 14.62 - 5.95 159.29 102.59 56.69 - 56.69 0.9496 53.84

2013 16.50 7.43 116.12 862.20 172.44 16.71 42.63 66.33 10.71 553.39 389.52 163.87 0.60 163.26 0.8877 144.93 2014 22.03 9.91 108.69 1,077.40 215.48 20.80 50.26 85.32 10.71 694.83 463.03 231.80 2.33 229.47 0.8070 185.19 2015 28.78 12.95 104.06 1,347.52 269.50 27.08 64.18 146.13 10.71 829.92 549.52 280.40 3.54 276.85 0.7337 203.12 2016 37.07 16.68 106.14 1,770.53 354.11 36.21 76.26 220.65 10.71 1,072.60 715.81 356.79 5.45 351.33 0.6668 234.27 2017 49.19 22.13 108.26 2,396.30 479.26 47.78 92.75 267.32 10.71 1,498.47 1,217.16 281.32 8.58 272.74 0.6062 165.33 2018 55.40 24.93 110.43 2,752.97 550.59 53.00 102.53 247.81 10.71 1,788.31 1,439.92 348.40 17.42 330.98 0.5511 182.39 2019 62.27 28.02 112.64 3,156.29 631.26 59.81 113.92 255.68 10.71 2,084.91 1,675.81 409.10 40.29 368.81 0.5010 184.76 2020 57.56 25.90 114.89 2,975.78 595.16 54.43 110.07 173.99 10.71 2,031.42 1,609.26 422.15 42.22 379.94 0.4553 172.99 2021 43.64 19.64 117.19 2,301.54 460.31 40.45 95.34 72.60 10.71 1,622.12 1,261.78 360.35 36.03 324.31 0.4139 134.24 2022 30.70 13.81 119.53 1,651.10 330.22 29.27 80.69 51.69 10.71 1,148.52 888.09 260.42 26.04 234.38 0.3763 88.20 2023 29.61 13.32 121.92 1,624.31 324.86 28.81 81.35 50.36 10.71 1,128.21 880.40 247.82 24.78 223.03 0.3421 76.30 2024 23.63 10.63 124.36 1,322.15 264.43 23.94 74.61 51.36 10.71 897.10 705.55 191.55 19.15 172.39 0.3109 53.60 2025 9.84 4.43 126.85 561.91 112.38 10.57 56.53 17.46 10.71 354.25 238.11 116.13 11.61 104.52 0.2826 29.54 2026 8.82 3.97 129.38 513.80 102.76 9.28 56.22 - 10.71 334.83 225.64 109.19 10.92 98.27 0.2569 25.25 2027 8.09 3.64 131.97 480.40 96.08 8.74 56.26 - 10.71 308.60 209.95 98.65 9.87 88.79 0.2336 20.74 2028 5.83 2.62 134.61 352.91 70.58 6.68 54.25 - 10.71 210.68 143.64 67.05 6.70 60.34 0.2123 12.81 2029 5.53 2.49 137.30 341.39 68.28 6.51 54.92 - 10.71 200.97 138.98 62.00 6.20 55.80 0.1930 10.77 2030 5.26 2.37 140.05 331.33 66.27 6.35 55.54 - 10.71 192.46 134.39 58.07 5.81 52.26 0.1755 9.17 2031 4.79 2.15 142.85 307.66 61.53 5.98 55.87 - 10.71 173.57 121.50 52.07 5.21 46.86 0.1595 7.47 2032 4.04 1.82 145.71 264.79 52.96 5.29 55.77 - 10.71 140.06 98.04 42.02 4.20 37.82 0.1450 5.48 2033 3.30 1.48 148.62 220.50 44.10 4.57 55.14 - 10.71 105.97 74.18 31.79 3.18 28.61 0.1318 3.77 2034 3.16 1.42 151.59 215.55 43.11 4.50 55.73 - 10.71 101.50 71.05 30.45 3.05 27.41 0.1198 3.28 2035 3.05 1.37 154.63 211.96 42.39 4.45 56.67 - 10.71 97.73 68.41 29.32 2.93 26.39 0.1089 2.87 2036 2.10 0.95 157.72 149.27 29.85 3.44 55.95 - 10.71 49.31 34.51 14.79 1.48 13.31 0.0990 1.32 2037 2.01 0.91 160.87 145.82 29.16 3.40 56.93 - 10.71 45.61 31.93 13.68 1.37 12.32 0.0900 1.11 2038 1.47 0.66 164.09 108.49 21.70 2.80 56.93 - 10.71 16.35 11.44 4.90 0.49 4.41 0.0818 0.36 2039 1.41 0.64 167.37 106.35 21.27 2.78 57.98 - 10.71 13.61 9.53 4.08 0.41 3.67 0.0744 0.27 2040 1.36 0.61 170.72 104.29 20.86 2.75 59.05 - 10.71 10.91 7.64 3.27 0.33 2.95 0.0676 0.20 2041 1.30 0.59 174.13 102.13 20.43 2.73 59.67 - 10.71 8.59 6.02 2.58 0.26 2.32 0.0614 0.14 2042 1.26 0.57 177.62 100.38 20.08 2.71 60.78 - 10.71 6.10 4.27 1.83 0.18 1.65 0.0559 0.09 2043 1.21 0.54 181.17 98.71 19.74 2.69 61.92 - 10.71 3.64 2.55 1.09 0.11 0.98 0.0508 0.05 2044 1.17 0.53 184.79 97.11 19.42 2.68 63.09 - 10.71 1.21 0.84 0.36 0.04 0.33 0.0462 0.02 2045 1.13 0.51 188.49 95.58 19.12 2.67 64.28 - 10.71 (1.20) - (1.20) (0.12) (1.08) 0.0420 (0.05) 2046 1.09 0.49 192.26 94.13 18.83 2.64 64.18 - 10.71 (2.23) - (2.23) (0.22) (2.01) 0.0381 (0.08) 2047 - - 196.10 - - - - - - - - - - - 0.0347 -

Total 540.96 241.95 28,472.52 5,694.50 546.60 2,272.89 1,706.71 370.22 17,881.60 13,531.05 4,350.55 300.45 4,050.11 NPV --> 2,013.76

OML 30 -- Proved case -- forecast (from 1 April 2012) of production and cashflows

Scenario: Alternative

Tax Scenario based on pending

legislation



ECV 1851 110 July 2012


basis

SP share



Received oil price




Cashflow before


Cashflow after

income tax


tax

Cashflow after

income tax

Discount factor

(@10%)

Cashflow after



2013 21.57 9.70 116.12 1,126.87 225.37 20.99 47.46 66.33 10.47 756.26 522.91 233.35 2.37 230.98 0.8877 205.05 2014 29.63 13.33 108.69 1,449.33 289.87 27.31 58.23 101.33 10.47 962.12 646.82 315.30 4.42 310.88 0.8070 250.89 2015 40.88 18.40 104.06 1,914.22 382.84 36.45 79.79 150.84 10.47 1,253.83 828.72 425.11 7.16 417.95 0.7337 306.64 2016 55.09 24.79 106.14 2,631.25 526.25 51.07 99.51 249.44 10.47 1,694.50 1,129.39 565.11 10.66 554.45 0.6668 369.71 2017 77.34 34.80 108.26 3,768.05 753.61 70.04 128.07 265.92 10.47 2,539.93 2,044.44 495.49 39.85 455.65 0.6062 276.20 2018 95.96 43.18 110.43 4,768.41 953.68 85.87 153.49 251.38 10.47 3,313.52 2,657.44 656.08 65.61 590.47 0.5511 325.39 2019 112.03 50.41 112.64 5,678.33 1,135.67 100.78 176.42 255.68 10.47 3,999.30 3,203.25 796.05 79.60 716.44 0.5010 358.92 2020 109.14 49.11 114.89 5,642.33 1,128.47 97.05 177.05 150.27 10.47 4,079.02 3,239.85 839.17 83.92 755.25 0.4553 343.88 2021 102.22 46.00 117.19 5,390.57 1,078.11 90.65 172.35 72.60 10.47 3,966.38 3,137.09 829.29 82.93 746.36 0.4139 308.94 2022 84.38 37.97 119.53 4,538.90 907.78 76.13 153.29 49.37 10.47 3,341.86 2,642.06 699.79 69.98 629.82 0.3763 237.00 2023 71.37 32.12 121.92 3,915.52 783.10 66.06 140.22 50.36 10.47 2,865.31 2,271.32 593.99 59.40 534.59 0.3421 182.88 2024 60.64 27.29 124.36 3,393.44 678.69 57.61 127.79 51.36 10.47 2,467.52 1,963.36 504.16 50.42 453.74 0.3109 141.07 2025 26.58 11.96 126.85 1,517.12 303.42 26.13 83.62 17.46 10.47 1,076.01 850.39 225.62 22.56 203.06 0.2826 57.39 2026 24.50 11.03 129.38 1,426.73 285.35 24.15 82.35 - 10.47 1,024.41 809.87 214.54 21.45 193.09 0.2569 49.61 2027 22.66 10.20 131.97 1,345.48 269.10 22.83 81.03 - 10.47 962.05 762.85 199.20 19.92 179.28 0.2336 41.88 2028 18.10 8.15 134.61 1,096.48 219.30 18.80 75.68 - 10.47 772.24 536.73 235.51 23.55 211.96 0.2123 45.00 2029 17.29 7.78 137.30 1,068.00 213.60 18.34 76.04 - 10.47 749.54 522.98 226.57 22.66 203.91 0.1930 39.35 2030 15.73 7.08 140.05 991.13 198.23 17.11 75.32 - 10.47 690.01 482.67 207.33 20.73 186.60 0.1755 32.74 2031 15.30 6.89 142.85 983.59 196.72 16.99 75.91 - 10.47 683.50 478.45 205.05 20.50 184.54 0.1595 29.44 2032 14.66 6.60 145.71 961.00 192.20 16.64 76.47 - 10.47 665.22 465.66 199.57 19.96 179.61 0.1450 26.04 2033 13.93 6.27 148.62 931.64 186.33 16.17 76.59 - 10.47 642.09 449.46 192.63 19.26 173.36 0.1318 22.85 2034 11.17 5.03 151.59 762.32 152.46 13.43 73.60 - 10.47 512.35 358.65 153.71 15.37 138.33 0.1198 16.57 2035 9.59 4.31 154.63 666.98 133.40 11.89 72.12 - 10.47 439.10 307.37 131.73 13.17 118.56 0.1089 12.91 2036 8.93 4.02 157.72 633.74 126.75 11.36 72.50 - 10.47 412.66 288.86 123.80 12.38 111.42 0.0990 11.03 2037 5.48 2.46 160.87 396.38 79.28 7.51 67.67 - 10.47 231.45 162.01 69.43 6.94 62.49 0.0900 5.62 2038 4.44 2.00 164.09 327.80 65.56 6.41 67.27 - 10.47 178.08 124.66 53.42 5.34 48.08 0.0818 3.93 2039 4.32 1.94 167.37 325.48 65.10 6.39 68.31 - 10.47 175.22 122.65 52.57 5.26 47.31 0.0744 3.52 2040 4.21 1.89 170.72 323.42 64.68 6.36 68.55 - 10.47 173.36 121.35 52.01 5.20 46.81 0.0676 3.16 2041 4.10 1.85 174.13 321.61 64.32 6.34 69.74 - 10.47 170.73 119.51 51.22 5.12 46.10 0.0614 2.83 2042 3.94 1.77 177.62 315.06 63.01 6.24 70.85 - 10.47 164.49 115.14 49.35 4.93 44.41 0.0559 2.48 2043 3.85 1.73 181.17 313.78 62.76 6.24 72.10 - 10.47 162.21 113.55 48.66 4.87 43.80 0.0508 2.22 2044 3.76 1.69 184.79 312.67 62.53 6.23 73.38 - 10.47 160.05 112.03 48.01 4.80 43.21 0.0462 1.99 2045 3.68 1.65 188.49 311.73 62.35 6.23 74.70 - 10.47 157.98 110.59 47.40 4.74 42.66 0.0420 1.79 2046 3.59 1.62 192.26 310.94 62.19 6.23 76.04 - 10.47 156.01 109.21 46.80 4.68 42.12 0.0381 1.61 2047 2.99 1.34 196.10 263.72 52.74 5.48 76.07 - 10.47 118.96 83.27 35.69 3.57 32.12 0.0347 1.11 2048 2.93 1.32 200.03 263.31 52.66 5.48 77.47 - 10.47 117.22 82.05 35.17 3.52 31.65 0.0315 1.00 2049 2.86 1.29 204.03 263.00 52.60 5.49 78.90 - 10.47 115.54 80.88 34.66 3.47 31.19 0.0287 0.89 2050 - - 208.11 - - - - - - - - - - - 0.0260 -

Total 1,117.82 501.22 60,929.96 12,185.99 1,079.36 3,391.63 1,732.35 393.28 42,147.35 32,185.09 9,962.26 850.57 9,111.68 NPV --> 3,789.47

OML 30 -- Proved + Probable case -- forecast (from 1 April 2012) of production and cashflows



legislation

SNRL 45% w orking interest basis HOG share


ECV 1851 111 July 2012


basis

SP share



Received oil price




Cashflow before


Cashflow after

income tax


tax

Cashflow after

income tax

Discount factor

(@10%)

Cashflow after



2013 27.29 12.28 116.12 1,425.99 285.20 25.84 53.51 66.33 10.47 984.64 673.07 311.57 4.32 307.25 0.8877 272.76 2014 37.47 16.86 108.69 1,832.65 366.53 33.93 67.93 114.53 10.47 1,239.26 835.68 403.58 6.62 396.95 0.8070 320.36 2015 51.59 23.22 104.06 2,415.84 483.17 44.45 91.34 146.13 10.47 1,640.29 1,078.88 561.41 10.57 550.84 0.7337 404.14 2016 72.22 32.50 106.14 3,449.31 689.86 64.45 117.63 252.88 10.47 2,314.02 1,537.45 776.57 15.95 760.63 0.6668 507.19 2017 104.83 47.17 108.26 5,107.25 1,021.45 92.02 158.32 274.33 10.47 3,550.66 2,856.45 694.21 61.34 632.88 0.6062 383.64 2018 128.25 57.71 110.43 6,372.86 1,274.57 111.88 190.08 250.67 10.47 4,535.18 3,631.41 903.77 90.38 813.40 0.5511 448.24 2019 156.70 70.52 112.64 7,942.74 1,588.55 137.67 228.51 260.06 10.47 5,717.49 4,578.70 1,138.79 113.88 1,024.91 0.5010 513.46 2020 151.33 68.10 114.89 7,823.69 1,564.74 132.45 227.12 150.27 10.47 5,738.64 4,565.62 1,173.02 117.30 1,055.72 0.4553 480.69 2021 142.76 64.24 117.19 7,528.30 1,505.66 125.35 222.27 72.60 10.47 5,591.95 4,435.59 1,156.36 115.64 1,040.73 0.4139 430.78 2022 126.26 56.82 119.53 6,791.58 1,358.32 112.71 206.49 49.37 10.47 5,054.22 4,010.88 1,043.34 104.33 939.01 0.3763 353.34 2023 111.33 50.10 121.92 6,107.95 1,221.59 101.65 191.31 50.36 10.47 4,532.57 3,604.54 928.03 92.80 835.23 0.3421 285.72 2024 95.31 42.89 124.36 5,333.94 1,066.79 89.12 174.14 51.36 10.47 3,942.05 3,142.70 799.35 79.93 719.41 0.3109 223.67 2025 57.06 25.68 126.85 3,257.03 651.41 54.39 126.10 17.46 10.47 2,397.19 1,907.33 489.86 48.99 440.87 0.2826 124.61 2026 53.19 23.93 129.38 3,096.63 619.33 51.27 122.47 - 10.47 2,293.09 1,824.82 468.28 46.83 421.45 0.2569 108.29 2027 47.17 21.23 131.97 2,801.33 560.27 46.48 116.46 - 10.47 2,067.65 1,647.34 420.32 42.03 378.29 0.2336 88.36 2028 38.04 17.12 134.61 2,304.51 460.90 38.41 104.62 - 10.47 1,690.10 1,347.69 342.41 34.24 308.17 0.2123 65.42 2029 34.08 15.34 137.30 2,105.90 421.18 35.20 100.73 - 10.47 1,538.33 1,228.71 309.61 30.96 278.65 0.1930 53.78 2030 28.48 12.81 140.05 1,794.73 358.95 30.16 94.54 - 10.47 1,300.62 1,040.12 260.50 26.05 234.45 0.1755 41.13 2031 27.70 12.46 142.85 1,780.61 356.12 29.94 95.29 - 10.47 1,288.79 1,031.03 257.76 25.78 231.98 0.1595 37.00 2032 26.97 12.14 145.71 1,768.66 353.73 29.75 96.02 - 10.47 1,278.69 1,022.95 255.74 25.57 230.16 0.1450 33.37 2033 24.51 11.03 148.62 1,639.00 327.80 27.66 94.16 - 10.47 1,178.91 943.13 235.78 23.58 212.20 0.1318 27.97 2034 20.99 9.44 151.59 1,431.76 286.35 24.30 89.91 - 10.47 1,020.72 816.57 204.14 20.41 183.73 0.1198 22.01 2035 20.50 9.23 154.63 1,426.76 285.35 24.23 90.84 - 10.47 1,015.86 812.69 203.17 20.32 182.85 0.1089 19.92 2036 17.29 7.78 157.72 1,226.80 245.36 21.00 87.32 - 10.47 862.66 603.86 258.80 25.88 232.92 0.0990 23.06 2037 16.53 7.44 160.87 1,196.66 239.33 20.52 87.82 - 10.47 838.52 586.96 251.56 25.16 226.40 0.0900 20.37 2038 14.86 6.68 164.09 1,096.92 219.38 18.91 86.74 - 10.47 761.41 532.99 228.42 22.84 205.58 0.0818 16.82 2039 14.54 6.54 167.37 1,095.30 219.06 18.90 87.72 - 10.47 759.16 531.41 227.75 22.77 204.97 0.0744 15.24 2040 12.40 5.58 170.72 952.53 190.51 16.59 85.23 - 10.47 649.73 454.81 194.92 19.49 175.43 0.0676 11.86 2041 11.93 5.37 174.13 934.75 186.95 16.30 85.38 - 10.47 635.64 444.95 190.69 19.07 171.62 0.0614 10.55 2042 11.49 5.17 177.62 918.66 183.73 16.05 85.93 - 10.47 622.48 435.73 186.74 18.67 168.07 0.0559 9.39 2043 6.79 3.06 181.17 553.49 110.70 10.14 78.85 - 10.47 343.33 240.33 103.00 10.30 92.70 0.0508 4.71 2044 6.66 3.00 184.79 553.62 110.72 10.15 80.19 - 10.47 342.09 239.46 102.63 10.26 92.36 0.0462 4.26 2045 6.53 2.94 188.49 553.60 110.72 10.17 81.42 - 10.47 340.82 238.58 102.25 10.22 92.02 0.0420 3.86 2046 6.21 2.79 192.26 536.91 107.38 9.91 82.42 - 10.47 326.73 228.71 98.02 9.80 88.22 0.0381 3.36 2047 6.10 2.74 196.10 537.97 107.59 9.94 83.72 - 10.47 326.25 228.37 97.87 9.79 88.09 0.0347 3.05 2048 5.99 2.70 200.03 539.23 107.85 9.97 85.18 - 10.47 325.75 228.03 97.73 9.77 87.95 0.0315 2.77 2049 5.89 2.65 204.03 540.68 108.14 10.01 86.68 - 10.47 325.37 227.76 97.61 9.76 87.85 0.0287 2.52 2050 - - 208.11 - - - - - - - - - - - 0.0260 -

Total 1,738.02 779.95 97,111.70 19,422.34 1,667.68 4,261.06 1,756.33 393.28 69,611.01 53,951.06 15,659.95 1,382.29 14,277.66 NPV --> 5,457.15



legislation


EVALUATION OF HERITAGE OIL PLc’s PETROLEUM … · RPS Energy Heritage – CPR RPS has assessed...

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Transcript of EVALUATION OF HERITAGE OIL PLc’s PETROLEUM … · RPS Energy Heritage – CPR RPS has assessed...