AGR TRACS Competent Person's Report on Otakikpo Marginal Field, OML 11, Nigeria, for Lekoil

AGR TRACS Competent Person’s Report on Otakikpo Marginal Field,

OML 11, Nigeria, for Lekoil

Otakikpo Marginal Field Location Map, Niger Delta

Peter Chandler, Liam Finch, Simon Moy,

Russell Parsons, Ksenia Shmyglia, Bjørn Smidt-Olsen

23rd September 2014

AGR TRACS CPR on Otakikpo for Lekoil

AGR TRACS International Ltd September 2014

This report was prepared in accordance with standard geological and engineering methods generally accepted by the oil and gas industry, in particular the 2007 SPE PRMS. Estimates of hydrocarbon reserves and resources should be regarded only as estimates that may change as further production history and additional information become available. Not only are reserves and resource estimates based on the information currently available, these are also subject to uncertainties inherent in the application of judgemental factors in interpreting such information. AGR TRACS International Ltd shall have no liability arising out of or related to the use of the report.

A comprehensive glossary of technical terms, units, and abbreviations commonly used is included at the back of the report.

Status Approved

Date 23rd September 2014

Issued by

Peter Chandler Liam Finch Simon Moy

Russell Parsons Ksenia Shmyglia

Bjørn Smidt-Olsen

Approved by Nigel Blott


AGR TRACS International Ltd September 2014 i

AGR TRACS Competent Person’s Report on Otakikpo, OML 11, Nigeria

Contents Figures ...................................................................................................................iv

Tables ....................................................................................................................vi

Cover Letter ............................................................................................................ix

Disclaimer ............................................................................................................. xiii

Executive Summary ................................................................................................. xv

1. Introduction ........................................................................................................ 1

2. Geoscience Review ............................................................................................... 3

2.1. Data available ................................................................................................ 3

2.2. Seismic Interpretation ..................................................................................... 4

2.2.1. C5000 ..................................................................................................... 5

2.2.2. C6000 ..................................................................................................... 6

2.2.3. C7000 ..................................................................................................... 8

2.2.4. E1000 ..................................................................................................... 9

2.3. Depth Conversion and Depth maps.................................................................. 10

2.3.1. C5000 ................................................................................................... 11

2.3.2. C6000 ................................................................................................... 12

2.3.3. C7000 ................................................................................................... 12

2.3.4. E1000 ................................................................................................... 13

2.4. Prospects .................................................................................................... 15

2.4.1. C5000 Prospects ..................................................................................... 15

2.4.2. C6000 Prospects ..................................................................................... 16

2.4.3. C7000 Prospects ..................................................................................... 18

2.4.4. E1000 Prospects ..................................................................................... 19

3. Otakikpo Petrophysics Review .............................................................................. 22

3.1. AGR TRACS quick-look petrophysical review ..................................................... 22

3.2. Otakikpo sums and averages .......................................................................... 25


AGR TRACS International Ltd September 2014 ii

4. In-Place Volumetric Estimates .............................................................................. 27

4.1. Otakikpo HIIP estimates ................................................................................ 27

4.1.1. Otakikpo Reservoir Property inputs ............................................................ 27

4.1.2. C5000 Volumetric estimates ..................................................................... 28



4.1.5. E1000 Volumetric estimates ..................................................................... 31

4.1.6. STOIIP and GIIP Summary ....................................................................... 32

4.2. Otakikpo Prospect HIIP Estimates ................................................................... 32

4.2.1. C5000 Prospects. .................................................................................... 32

4.2.2. C6000 Prospects ..................................................................................... 33

4.2.3. C7000 Prospect ...................................................................................... 33

4.2.4. E1000 Prospects ..................................................................................... 34

4.2.5. Summary of volumes............................................................................... 35

5. OML 11 Reservoir Engineering Review ................................................................... 36

5.1. Introduction ................................................................................................. 36

5.2. PVT and Fluid Properties ................................................................................ 36

5.3. Volumetrics and Properties ............................................................................. 36

5.4. Model Construction ....................................................................................... 38

5.4.1. Wells ..................................................................................................... 40

5.4.2. Gas liberation ......................................................................................... 40

5.5. Forecast Scenarios ........................................................................................ 42

5.5.1. Production Profiles .................................................................................. 46

5.6. Results and Conclusions ................................................................................ 49

5.7. Further Studies ............................................................................................ 49

6. Otakikpo Facilities Review and Cost Estimates ........................................................ 50

6.1. Introduction ................................................................................................. 50

6.2. Overview of Otakikpo conceptual Central Production Facilities ............................. 51


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6.3. Otakikpo facilities cost estimates .................................................................... 53

7. Economic Evaluations .......................................................................................... 59

7.1. Summary of Otakikpo OML 11 Marginal Field Terms ........................................... 59

7.2. Economic Assumptions .................................................................................. 59

7.3. Economic Evaluations .................................................................................... 60

8. Contingent Resource Estimates ............................................................................ 61

8.1. Lekoil Net Contingent Resources under $80-$100-$120/bbl ................................ 61

8.2. AIM Summary Tables .................................................................................... 62

9. Conclusions ....................................................................................................... 67

10. APPENDIX 1 - Petroleum Resources Classification .................................................. 69

11. APPENDIX 2 - Glossary ...................................................................................... 71


AGR TRACS International Ltd September 2014 iv

Figures

Figure 1-1: Location map Otakikpo Marginal Field, OML 11, Nigeria ................................. 1

Figure 1-2: Otakikpo field location within Niger Delta .................................................... 2

Figure 1-3: Otakikpo farm-out area, OML 11 ................................................................ 2

Figure 2-1: Location map .......................................................................................... 3

Figure 2-2: Line 0011-77-02-0453 showing well ties ..................................................... 5

Figure 2-3: C5000 Two-Way Time map ....................................................................... 6

Figure 2-4: Line 0011-72-03-0254 showing amplitude anomaly ...................................... 7



Figure 2-7: E1000 Two-Way Time map ...................................................................... 10

Figure 2-8: C5000 Depth structure map .................................................................... 11

Figure 2-9: C6000 Depth structure map .................................................................... 12

Figure 2-10: C7000 Depth structure map .................................................................. 13

Figure 2-11: Sea Floor to E1000 Velocity Function ...................................................... 14

Figure 2-12: E1000 Depth structure map ................................................................... 14

Figure 2-13: C5000 Prospect locations ...................................................................... 15



Figure 2-16: E1000 Prospect locations ...................................................................... 20

Figure 3-1: CPI plot of C5000 reservoir in Otakikpo 002 .............................................. 23



Figure 3-4: CPI plot of E1000 in Otakikpo 002 ............................................................ 25

Figure 4-1: C5000 Reservoir depth map with contacts ................................................. 28




AGR TRACS International Ltd September 2014 v

Figure 4-4: E1000 Reservoir depth map with contacts ................................................. 31

Figure 5-1: Simulation grid showing top surface for the C5000 Horizon .......................... 38

Figure 5-2: Cross-sections of C6000 and C7000 reservoirs ........................................... 41

Figure 5-3: Wells and dual completion scheme ........................................................... 42

Figure 5-4: E1000 – Sensitivity of recovery vs. well numbers ....................................... 44

Figure 5-5: Otakikpo – Notional production profiles for the P90-P50-P10 cases ............... 47

Figure 6-1: Location map for planned Otakikpo production facilities ............................... 50

Figure 6-2: Conceptual lay-out of proposed Otakikpo CPF ............................................ 51

Figure 6-3: Conceptual process flow diagram for Otakikpo CPF ..................................... 52


AGR TRACS International Ltd September 2014 vi

Tables

Table 0-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil ... x

Table 0-2: Otakikpo Unrisked and Risked Contingent Resources and net attributable to Lekoil ............................................................................................................... x

Table 0-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited .................... xi

Table 0-4: Otakikpo exploration potential - Summary of 100% Unrisked STOIIPs ............. xi

Table ES-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil xvi

Table ES-2: Otakikpo Unrisked and Risked Contingent Resources net attributable to Lekoil ..................................................................................................................... xvi

Table ES-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited ................. xvi

Table 2-1: Well to Grid misties (-ve value means grid is deeper than the well) ................ 11

Table 2-2: C5000 Prospect C5 1 Probability of Success ................................................ 16






Table 2-8: E1000 Prospect E1 2 Probability of Success ................................................ 21

Table 2-9: E1000 Prospect E1 3 Probability of Success ................................................ 21

Table 2-10: E1000 Prospect E1 4 Probability of Success ............................................... 21

Table 3-1: Otakikpo area – Original permeability ranges from Shell ............................... 22

Table 3-2: Otakikpo - Reservoir parameters from Shell’s petrophysical analysis .............. 26

Table 3-3: Otakikpo – Shell’s sums and averages over oil and gas pay zones .................. 26

Table 4-1: Otakikpo Reservoir Property ranges (Oil) .................................................... 27

Table 4-2 Otakikpo Reservoir Property ranges (Gas) ................................................... 28

Table 4-3: C5000 STOIIP ........................................................................................ 29

Table 4-4: C5000 GIIP ............................................................................................ 29

Table 4-5: C6000 STOIIP ........................................................................................ 30


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Table 4-6: C7000 STOIIP ........................................................................................ 31

Table 4-7: E1000 STOIIP ........................................................................................ 32

Table 4-8 STOIIP and GIIP Summary by reservoir ....................................................... 32

Table 4-9: C5000 STOIIP ........................................................................................ 33

Table 4-10: C6000 STOIIP ....................................................................................... 33

Table 4-11: C7000 STOIIP ....................................................................................... 34

Table 4-12: E1000 STOIIP ....................................................................................... 34

Table 4-13: Prospect 1 STOIIP ................................................................................. 35




Table 5-1: Otakikpo – RFT sample parameters ........................................................... 36

Table 5-2: Model input parameters (P50 values) ......................................................... 37

Table 5-3: Initial pressures and contact depths .......................................................... 37

Table 5-4: Summary of initial Sw assumed for key reservoirs ....................................... 37

Table 5-5: Rel-perm values and end points ................................................................ 38

Table 5-6: Otakikpo - Model layer scheme ................................................................. 39

Table 5-7: E1000 - Summary of models runs with sensitivities of recovery vs. well numbers ..................................................................................................................... 44

Table 5-8: Otakikpo – Well schedule ......................................................................... 45

Table 5-9: Otakikpo - Monte Carlo results to determine ultimate recovery ...................... 45

Table 5-10: Otakikpo - Recoveries for the P50 case ..................................................... 46

Table 5-11: Otakikpo – Oil prod. profiles P90-P50-P10 cases (100%) ............................ 48

Table 6-1: Res. engineering inputs for P90-P50-P10 dev. scenarios ............................... 54

Table 6-2: Overview of AGR TRACS cost estimates for P90 Case ................................... 55

Table 6-3: Overview of AGR TRACS cost estimates for P50 Case with vertical wells .......... 55

Table 6-4: Overview of AGR TRACS cost estimates for P10 Case ................................... 56

Table 6-5: Overview of capex phasing for P90-P50-P10 cases ....................................... 57

Table 6-6: Opex assumptions for notional Otakikpo development cases ......................... 58


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Table 7-1: Otakikpo – Econ. results NPV(0%) for P90-P50-P10 cases net to Lekoil Limited 60

Table 7-2: Otakikpo – Econ. results NPV(10%) for P90-P50-P10 cases net to Lekoil Limited ..................................................................................................................... 60



Table 8-1: Otakikpo – Lekoil net P90-P50-P10 Unrisked Contingent Resources ................ 61

Table 8-2: AIM table of Otakikpo OML 11 Reserves; gross and net attributable to Lekoil ... 63

Table 8-3: AIM table of Otakikpo OML 11 Contingent Resources; gross and net attributable to Lekoil ......................................................................................................... 64

Table 8-4: AIM table of Otakikpo OML 11 Contingent Resources net attributable to Lekoil; unrisked and risked .......................................................................................... 65

Table 8-5: AIM table of Otakikpo OML 11 Unrisked Prospective Resources; gross and net attributable to Lekoil ........................................................................................ 66

Table 9-1: Otakikpo OML 11 Unrisked and Risked Contingent Resources net attributable to Lekoil ............................................................................................................. 67

Table 9-2: Otakikpo P90-P50-P10 cases - Economic results NPV(10%), unrisked net to Lekoil Limited .................................................................................................. 68


AGR TRACS International Ltd September 2014 ix

Cover Letter

Attn.: Lekan Akinyanmi/Dotun Adejuyigbe

Lekoil Limited c/o Intertrust Corporate services (Cayman) limited 190 Elgin Avenue George Town Grand Cayman KY1-9005 Cayman Islands

23rd September 2014

Gentlemen,

Competent Person’s Report on Otakikpo Marginal Field, OML 11, Nigeria

In response to your request AGR TRACS International Ltd (“AGR TRACS”) has carried out a comprehensive review of the subsurface data provided by Lekoil Limited1 on the Otakikpo Marginal Field in OML 11. Lekoil Oil and Gas Investments Limited (“Lekoil Oil and Gas”) 2 executed a farm-in agreement with the current licence holder Green Energy International Ltd (“Green Energy”) to acquire a 40% interest in Otakikpo, effective 17th May 2014. Lekoil Limited (“Lekoil”) holds a 90% economic interest in Lekoil Nigeria Limited (with the remainder held by other minority interests), thus the valuations and attributable resource volumes presented in this report are for Lekoil’s 36% interest in the Otakikpo Marginal Field.

The seismic and map information provided was of varied quality for the main reservoirs due to the seismic database comprising only 2D data of mixed vintages from the period 1967-1985. The log data from the three wells drilled in the early 1980’s (Otakikpo-001, -002 and -003) was of good quality, and supported by two MDT reports and fluid analyses. No test data was available, thus Lekoil provided representative ranges for reservoir permeability from analogue wells in the area.

The initial work programme planned for late 2014 to early 2015 will focus on two of the existing wells, with recompletions in the C6000 and E1000 reservoirs in the 002 well, and recompletions in the C5000 and E1000 reservoirs in the 003 well. A full-field development will follow in the period 2016-2018 with a further 7 wells planned (five vertical and two S-shaped wells, starting in Q4/2016), four of which are dual completions. This development scheme is not finalised, but AGR TRACS has developed independent cost estimates for the wells, onshore facilities and evacuation scheme as outlined by Lekoil in mid-July 2014.

There is no approved development plan at present, hence the volumes assumed to be recovered through the initial recompletions and the subsequent development scheme have been classified as Contingent Resources with a Chance Of Commercial Success (COCS) of 70%. The Contingent Resource estimates have been derived using an economic model provided by Lekoil and reviewed by AGR TRACS. This is considered to correctly represent the Marginal Field Terms applicable to Otakikpo. --------------------------------------------------------------------------------------------------------------------------------1 Lekoil Limited is registered in the Cayman Islands; it holds 90% of the economic interest in Lekoil Nigeria Limited, herein after referred to as “Lekoil Nigeria”. 2 Lekoil Oil and Gas is a wholly owned entity of Lekoil Nigeria.


AGR TRACS International Ltd September 2014 x

The net attributable volumes quoted in this report reflect the farm-in terms agreed with Green Energy in May 2014 in order to transfer a 40% equity interest in the Otakikpo Marginal Field in OML 11 to Lekoil Oil and Gas, with 90% of this interest attributable to Lekoil Limited. The completion of the transfer requires a formal approval from the Minister of Petroleum Resources. However, Lekoil Oil and Gas and Green Energy have executed a Financial and Technical Services Agreement (FTSA) whereby Lekoil Oil and Gas is entitled to a 40% economic interest in the Otakikpo Marginal Field. Under the terms of the farm-in agreement, Lekoil Oil and Gas will carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy’s share of the initial work program is reflected in Lekoil’s share of project NPV. Following the review, AGR TRACS can report that the net unrisked 1C-2C-3C (P90-P50-P10) Contingent Resources at $80/bbl attributable to Lekoil (effective from late 2014) are estimated to be 17.27-20.43-23.87 MMbbls, see Table 0-1. The corresponding net risked 1C-2C-3C (P90-P50-P10) contingent resources at $80/bbl attributable to Lekoil are estimated at 12.09-14.30-16.71 MMbbls oil, see Table 0-2 below.

Four exploration prospects have been identified. P90-P50-P10 STOIIP ranges have been estimated for these structures, however, insufficient data was available to enable economic evaluations to be carried out, thus no Prospective Resources can be estimated.

Oil MMbbls Gross (from 1.1.2015)

Net Attributable to Lekoil Limited (from 1.1.2015)

Risk Factor

Operator

1C Low

Estimate 2C Best Estimate

3C High Estimate

1C Low Estimate

2C Best Estimate

3C High Estimate

COCS (%)

Contingent Resources @$80/bbl

Otakikpo 47.96 56.75 66.31 17.27 20.43 23.87 70% Green Energy

Table 0-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil

Oil MMbbls

Unrisked Contingent Resources Net Attributable to Lekoil Limited

Risk Factor

Risked Contingent Resources Net Attributable to Lekoil Limited

1C Low


3C High Estimate

COCS (%)

1C Low Estimate

2C Best Estimate

3C High Estimate


Otakikpo 17.27 20.43 23.87 70% 12.09 14.30 16.71

Table 0-2: Otakikpo Unrisked and Risked Contingent Resources and net attributable to Lekoil

Economic evaluations have been carried out under $80-$100-$120/bbl oil price scenarios for the P90-P50-P10 cases with deviated wells from 1.1.2015 until end of economic life.

The NPV(10%) MOD results of the economic evaluations indicate that the planned development of the Otakikpo Marginal Field is a robust project under all three oil price scenarios (see Table 0-3 for the NPV(10%) results.


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Otakikpo Case

Cont. Resources @ $80/bbl (MMbbls)

NPV(10%) $mln MOD PV 1.1.2014

100% Lekoil Net $80 $100 $120

P90 47.96 17.27 199.4 279.1 360.0

P50 56.75 20.43 228.2 322.6 415.6

P10 66.31 23.87 277.8 378.6 479.4

Table 0-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited

Exploration potential

In addition to the Otakikpo discovery, four undrilled exploration prospects have been identified during the review of the 2D seismic data, as listed in Table 0-4 below.

Prospects 1 and 2 have potential stacked reservoirs, while Prospects 3 and 4 are restricted to the deeper E1000 horizon. Due to the lack of detailed technical data, only total STOIIP and associated risk factors (“POS”) have been estimated. Lekoil’s share would be 36% of the stated STOIIPs.

Table 0-4: Otakikpo exploration potential - Summary of 100% Unrisked STOIIPs

* Note: Totals are arithmetic summations

The work was undertaken by a team of AGR TRACS professional petroleum engineers and geoscientists based on data supplied by Lekoil. The data comprised details of licence and acreage interests, basic exploration geological and geophysical data, interpreted data, technical presentations, and Lekoil’s seismic interpretations. AGR TRACS has not independently checked title interests with Government or licence authorities.

Prospect Reservoir POS (%)

Unrisked 100% STOIIP (MMbls) P90 P50 P10

Prospect 1 C5000 0.224 4.8 7.0 10.3 C6000 0.168 10.7 15.2 21.3 C7000 0.168 14.3 20.8 30.4

TOTAL* 29.8 43.0 62.0

Prospect 2

C5000 0.269 1.9 2.6 3.6 C6000 0.235 5.4 7.9 11.8 C7000 0.235 15.6 22.8 33.0 E1000 0.235 4.5 6.7 9.8

TOTAL* 27.4 40.0 58.2

Prospect 3 E1000 0.196 41.4 62.8 94.2 TOTAL 41.4 62.8 94.2

Prospect 4 E1000 0.168 11.5 17.0 24.7 TOTAL 11.5 17.0 24.7


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In estimating prospective and contingent resources we have used the standard petroleum engineering techniques. These estimates are based on the joint definitions of the Society of Petroleum Engineer, the World Petroleum Congress, the American Association of Petroleum Geologists and the 2007 PRMS (Petroleum Resources Management System). AGR TRACS has not conducted a site visit to independently verify the existence of physical assets.

Qualifications

AGR TRACS International Ltd is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, AGR TRACS International Ltd does not have a commercial arrangement with any other person or company involved in the interests that are the subject of this report.

The project was managed and signed off by Nigel Blott (M.Eng.), an AGR TRACS Manager. Mr. Blott, a petroleum engineer and SPE Member, has 30+ years’ experience from the Middle East, South-East Asia, and NW Europe. AGR TRACS International Ltd has conducted valuations for many energy companies and financial institutions.

Basis of Opinion

The evaluation presented in this report 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 subsurface reservoir data.

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.

Yours faithfully,

Nigel Blott AGR TRACS International Ltd


AGR TRACS International Ltd September 2014 xiii

Disclaimer

COMPETENT PERSON’S REPORT ON LEKOIL LIMITED’s 36% FARM-IN

INTEREST IN THE OTAKIKPO MARGINAL FIELD, OML 11, NIGERIA

This report relates specifically and solely to the subject petroleum licence interests and is conditional upon the assumptions made therein. This report must therefore be read in its entirety.

This report was prepared in accordance with standard geological and engineering methods generally accepted by the oil and gas industry. Estimates of prospective hydrocarbon resources should be regarded only as estimates that may change as additional information become available. Not only are these estimates based on the information currently available, but are also subject to uncertainties inherent in the application of judgemental factors in interpreting such information. AGR TRACS International Ltd shall have no liability arising out of, or related to, the use of the report.

23rd September 2014


AGR TRACS International Ltd September 2014 xiv

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AGR TRACS International Ltd September 2014 xv

Executive Summary

The Otakikpo Marginal Field in OML 11, onshore Nigeria, was farmed out by the SPDC JV (NNPC/Shell/Total/Agip) to Green Energy International Limited (with approval by the Minister of Petroleum Resources) in January 2014. Lekoil Oil and Gas executed a farm-in agreement with the current licence holder Green Energy International Ltd (“Green Energy”) to acquire a 40% interest in Otakikpo, effective 17th May 2014, and expects to commence the first phase of development work in late 2014. Lekoil Oil and Gas is wholly owned by Lekoil Nigeria; while Lekoil Limited (“Lekoil”) holds a 90% interest in Lekoil Nigeria (with the remainder held by other minority interests), thus the valuations and attributable resource volumes presented in this report are for Lekoil’s 36% interest in the Otakikpo Marginal Field.

AGR TRACS has carried out a comprehensive review of the surface and subsurface data provided by Lekoil from the Otakikpo field. The seismic and map information provided was of varied quality for the main reservoirs due to the seismic database comprising only 2D data of mixed vintages from the period 1967-1985. The log data from the three wells drilled in the early 1980’s (Otakikpo-001, -002 and -003) was of good quality, and supported by two MDT reports and fluid analyses. No test data was available, thus Lekoil provided representative ranges for reservoir permeability from analogue wells in the area.

The initial work programme planned for late 2014 to early 2015 will focus on two of the existing wells, with recompletions in the C6000 and E1000 reservoirs in the 002 well, and recompletions in the C5000 and E1000 reservoirs in the 003 well. A full-field development will follow in the period 2016-2018 with a further 7 wells planned (five vertical and two S-shaped wells, starting in Q4/2016), four of which are dual completions. This development scheme is not finalised, but AGR TRACS has developed independent cost estimates for the wells, onshore facilities and evacuation scheme as outlined by Lekoil in mid-July 2014.

There is no approved development plan at present, hence the volumes assumed to be recovered through the initial recompletions and the subsequent development scheme have been classified as Contingent Resources with a Chance Of Commercial Success (COCS) of 70%. The Contingent Resource estimates have been derived using an economic model provided by Lekoil and reviewed by AGR TRACS. This is considered to correctly represent the Marginal Field Terms applicable to Otakikpo.

The net attributable volumes quoted in this report reflect the farm-in terms agreed with Green Energy in May 2014 in order to transfer a 40% equity interest in the Otakikpo Marginal Field in OML 11 to Lekoil Oil and Gas, with 90% of this interest attributable to Lekoil Limited. The completion of the transfer requires a formal approval from the Minister of Petroleum Resources. However, Lekoil Oil and Gas and Green Energy have executed a Financial and Technical Services Agreement (FTSA) whereby Lekoil Oil and Gas is entitled to a 40% economic interest in the Otakikpo Marginal Field. Under the terms of the farm-in agreement, Lekoil Oil and Gas will carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy’s share of the initial work program is reflected in Lekoil’s share of project NPV. Following the review, AGR TRACS can report that the net unrisked 1C-2C-3C (P90-P50-P10) Contingent Resources at $80/bbl attributable to Lekoil (effective from late 2014) are estimated to be 17.27-20.43-23.87 MMbbls, see Table ES-1. The corresponding net risked 1C-2C-3C (P90-P50-P10) contingent resources at $80/bbl attributable to Lekoil are estimated at 12.09-14.30-16.71 MMbbls oil, see Table ES-2 below.


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Risk Factor

Operator

1C Low


3C High Estimate

1C Low Estimate

2C Best Estimate

3C High Estimate

COCS (%)



Table ES-1: Otakikpo Unrisked Contingent Resources; gross and net attributable to Lekoil

Oil MMbbls


Risk Factor


1C Low


3C High Estimate

COCS (%)

1C Low Estimate

2C Best Estimate

3C High Estimate


Otakikpo 17.27 20.43 23.87 70% 12.09 14.30 16.71

Table ES-2: Otakikpo Unrisked and Risked Contingent Resources net attributable to Lekoil

Economic evaluations have been carried out under $80-$100-$120/bbl oil price scenarios for the P90-P50-P10 cases from 1.1.2015 until the end of the economic life of the field.

The NPV(10%) MOD results of the economic evaluations indicate that the planned development of the Otakikpo Marginal Field is a robust project under all three oil price scenarios (see Table ES-3 for the NPV(10%) results).

Otakikpo Case


NPV(10%) $mln MOD PV 1.1.2014

100% Lekoil Net $80 $100 $120

P90 47.96 17.27 199.4 279.1 360.0

P50 56.75 20.43 228.2 322.6 415.6

P10 66.31 23.87 277.8 378.6 479.4

Table ES-3: Otakikpo P90-P50-P10 Unrisked NPV(10%) net to Lekoil Limited


AGR TRACS International Ltd September 2014 1

1. Introduction

On 21st January 2014, the Minister of Petroleum approved the farmout of the Otakikpo Marginal Field by Shell Petroleum Development Company (“SPDC”, 30%), Total E&P Nigeria Limited (“TEPNG, 10%), and Nigerian Agip Oil Company Limited (“NAOC”, 5%) and Nigerian National Petroleum Corporation (“NNPC”, 55%) (jointly “the SPDC JV”) to Green Energy International Limited (“Green Energy”). Otakikpo was discovered in 1981 and is located within OML 11 close to the coast and some 32km east of the Bonny oil terminal, see Figure 1-1 and Figure 1-2.

Figure 1-1: Location map Otakikpo Marginal Field, OML 11, Nigeria

The area included in the farm-out is defined by four corner points (A-D) and measures approximately 6.6 x 8.3 km, or some 55 sq km, see Figure 1-3. The farm-out is restricted in depth to 11,807ft TVDss. There are no surface facilities within the Otakikpo Marginal Field area, but three wells were drilled in the period 1981-1986 (Otakikpo-001, -002 and -003).

The coordinates of the four corner points (A-D) shown in Figure 1-3 are as follows:

Eastings Northings

A 550024.55mE 52882.27mN B 558340.41mE 52882.27mN C 558340.41mE 46248.78mN D 550024.55mE 46248.99mN

In May 2014 Lekoil announced they had farmed into Otakikpo, and this report provides an independent review of the field including estimates of net unrisked and risked Contingent Resources attributable to Lekoil.



Figure 1-2: Otakikpo field location within Niger Delta

Figure 1-3: Otakikpo farm-out area, OML 11



2. Geoscience Review

The objective of this review was to evaluate the four reservoirs that have been discovered by the Otakikpo-002 and Otakikpo-003 wells. These are the C5000, C6000, C7000 and E1000 reservoirs. The Otakikpo-001 well failed to encounter any hydrocarbons due to the absence of the reservoir.

Exploration prospects were also identified and briefly reviewed.

Figure 2-1 shows the location of the field, the Otakikpo farm-out area, and the surrounding blocks. The Otakikpo farm-out area lies within OML 11.

Figure 2-1: Location map

The aim of this section is to summarise the geoscience data provided for OML 11 and assess the volumetric potential of the Otakikpo discovery.

2.1. Data available The primary source of data was a Petrel project which contained 2D seismic lines, well data and interpreted horizons. These data were exported and used to create a Kingdom seismic project where the evaluation was conducted.



The seismic dataset consists of 18 2D lines, 12 of which are dip lines with a north–south orientation, four are strike lines with an approximately west–east orientation and one line has a northwest–southeast direction. It is not clear when the seismic data was acquired but based on the line numbering it is assumed that acquisition occurred at various times between 1967 and 1985.

There are no details on the acquisition or processing parameters. It is not known if the data provided is the originally processed data or more recently re-processed versions. In any event, the data quality is fair to poor.

The well data consists of limited log data and in the case of the Otakikpo-001 well, no Sonic data was available to generate a synthetic. It was possible to create synthetics for the Otakikpo-002 and Otakikpo-003 wells and reasonable ties to the seismic were possible.

Formation tops were provided and were found to be a good representation of the reservoir units in the Otakikpo-002 and Otakikpo-003 wells. The lack of reservoir in the Otakikpo-001 well makes correlation very difficult and the tops are considered unreliable in most cases.

Note that Lekoil are planning to acquire a 3D survey over the field, most likely in early 2016 prior to the main phase of development drilling.

2.2. Seismic Interpretation The fault and horizon interpretation provided by Lekoil was reviewed and although in part provided a useful framework, due to the poor quality of the data it was found that there were some inconsistencies that needed to be assessed. It was therefore decided to carry out an independent interpretation to provide an alternative view of the structures.

Four horizons were interpreted corresponding to the four reservoirs discovered in the wells. Figure 2-2 shows a north – south line through the Otakikpo-002 well and the interpreted reflectors.



Figure 2-2: Line 0011-77-02-0453 showing well ties

The following sections summarise the results of this interpretation.

2.2.1. C5000 The C5000 horizon is the shallowest of the reservoirs encountered and is interpreted as a peak on the seismic data (Figure 2-2 above). A number of significant faults have been interpreted and these appear to have a dominant west – east trend. The northern faults are major features that down throw to the south. The faults further to the south are antithetic with throws to the north.

The Otakikpo-002 and Otakikpo-003 wells both encountered oil in the C5000 reservoir. However, the Otakikpo-002 well also discovered a gas cap which was not seen in the Otakikpo-003 well. It is therefore interpreted that the two wells are in separate compartments.



The C5000 horizon was interpreted on all of the 2D seismic lines although the six lines in the southern part of the area were difficult to include as they do not intersect with any of the other lines available so ensuring the correct reflector is correlated is problematic. A reasonable correlation was made across the gap between the lines to the north and the southern lines but this is an area of uncertainty that will remain until additional seismic data is acquired to tie this area properly.

The faults were correlated and a general west–east trend was established. The horizon was gridded to generate a Two-Way Time (TWT) structure map which is shown in Figure 2-3 below. The faults provide the mechanism required to separate the Otakikpo-002 and Otakikpo-003 wells.

Figure 2-3: C5000 Two-Way Time map

The TWT map shows the Otakikpo wells to be on a relative structural high with the Otakikpo-002 well in a separate fault compartment to the Otakikpo-003 well. The surface dips to the south as seen on the seismic data.

2.2.2. C6000

The C6000 horizon has been picked as a trough on the seismic data which, at the Otakikpo-002 well and to the north of the Otakikpo-003 well has a reasonably high amplitude. Away from the wells it is a poorer quality event and so is more difficult to



correlate around the lines. However, it is close to the C5000 reflector which was used as a guide to interpreting the C6000 horizon. As with the C5000 horizon, correlating the C6000 event onto the southern lines is difficult and in this area the interpretation has some uncertainty. However, based on the resulting TWT map which shows a smooth transition across this area, it is considered that this interpretation provides a good representation of the C6000 surface.

Figure 2-4 shows a north–south line close to the Otakikpo-003 well showing the high amplitude features to the north of the well. This anomaly may be indicative of the presence of hydrocarbons although with only 2D seismic data available, the extent of this anomaly cannot be fully defined.

Figure 2-4: Line 0011-72-03-0254 showing amplitude anomaly

At this level, only the Otakikpo-002 well found hydrocarbons although the depths to the top of the C6000 sand are similar in both the Otakikpo-002 well and the Otakikpo-003 well. It appears that the fault between the two penetration points is again having an influence on the fluid distribution.



The interpreted horizon was gridded and the resulting TWT structure map is shown in Figure 2-5 below.


The TWT map shows a similar trend to the C5000 map with the Otakikpo-002 and Otakikpo-003 wells in separate compartments.

2.2.3. C7000

The C7000 event was picked as a trough. At the Otakikpo-002 and north of the Otakikpo-003 well the amplitude is relatively bright. It is less bright at the Otakikpo-003 location and it is possible that the amplitude is providing some indication of the presence of hydrocarbons as no oil was encountered at the Otakikpo-003 location. With 2D data this is difficult to quantify but 3D may provide a better correlation.

The lines to the south which have no direct intersections with the lines to the north have again been jump correlated. The resulting map shows a smooth transition across the gap between the two sets of lines.

The C7000 interpretation was gridded and the resulting TWT map is shown in Figure 2-6 below.




The penetration point of the Otakikpo-003 well is interpreted to be to the south of the west-east trending fault which provides an explanation for the lack of hydrocarbons in the Otakikpo-003 well.

2.2.4. E1000

The E1000 horizon is the deepest of the reservoirs intersected. It has been interpreted as a peak above a relatively bright peak / trough doublet. At this level, it appears that the Otakikpo-003 well intersects the E1000 horizon to the north of the west–east fault. This well encountered oil as did the Otakikpo-002 well. The Oil Water Contact is slightly different in the two wells although the Otakikpo-003 well is significantly deviated so it is possible that there is an error with the deviation such that the contacts could be the same in both wells. For the purpose of this evaluation, it has been assumed that the contact is the same and the deeper contact has been used.

There is a small closure to the south of the fault so if the well positioning is in error there may be some potential to the south of the fault although it is a small volume.

The gridded E1000 horizon is shown in Figure 2-7 below.



Figure 2-7: E1000 Two-Way Time map

The E1000 interpretation suffers the same problem with the lines to the south as the other horizons do but as in the other cases, the correlation across the gap seems reasonable as shown by the smooth contours on the TWT map.

At this level, the Otakikpo-003 well is interpreted as having crossed the west–east fault and penetrates the E1000 horizon to the north of the fault. This may be the reason that oil was encountered in both this well and the Otakikpo-002 well. It also leaves open the opportunity for a hydrocarbon accumulation to the south of the fault as detailed in Section 2.2.4 below.

2.3. Depth Conversion and Depth maps

In order to depth convert the TWT grids, a simple velocity model has been used. With only three wells available (and when one of those has significant uncertainty particularly in the placement of the tops), the scope for velocity analysis is limited. Simple average interval velocities were used for each layer although a simple function was found to give good results for the E1000 surface. The table below shows the well misties, in feet, using this method.



Horizon Otakikpo-001 Otakikpo-002 Otakikpo-003

C5000 12 -10 -13

C6000 32 8 27

C7000 Poor Tie 31 -11

E1000 -2 -1 -26

Table 2-1: Well to Grid misties (-ve value means grid is deeper than the well)

The depth values in the Otakikpo-001 well are unreliable given that there is no reservoir present and so correlating the age equivalent interval is difficult. Previous evaluations by other companies, including Shell, have tended to exclude the tops from this well and no significant effort has been made to tie the tops from this well in this evaluation. The following sections summarise the depth conversion approach used and shows the resulting depth maps for each horizon.

2.3.1. C5000

To create a depth map for the C5000 horizon, an average interval velocity of 7,520 ft/sec from sea bed to C5000 was applied. The resulting depth map is shown in Figure 2-8 below.

Figure 2-8: C5000 Depth structure map



The resulting map ties the wells closely and the closing contours agree with the various contacts seen in the wells. No significant editing was required to achieve this.

The depth errors at the wells are small for this horizon as seen in Table 2-1 above.

2.3.2. C6000

The C6000 depth map is the result of using an average interval velocity of 7,300 ft/sec for the C5000 to C6000 interval. This velocity was applied to the C5000 to C6000 isochron and the resulting isopach was added to the C5000 depth map to give the C6000 depth map which is shown Figure 2-9 below.


The well misties at this level are well within an acceptable range and again, no significant editing of the time interpretation was required to tie the contact data seen in the wells.

The well misties for this surface are shown in Table 2-1 above.

2.3.3. C7000

The C6000 to C7000 interval was used to generate the C7000 depth map. An interval velocity of 14,250 ft/sec was applied to the isochron wich resulted in a C6000 to C7000



isopach. This was added to the C6000 depth map resulting in the C7000 depth map shown in Figure 2-10.


The depth map is in close agreement with the well hydrocarbon contacts again without the need for any editing.

The well misties are shown in Table 2-1 above. The Otakikpo-001 well is a poor tie and this may be due to a mis-correlation of the horizon top.

2.3.4. E1000

To depth convert to the E1000 surface a simple Time / Velocity function from sea bed to E1000 was used as this resulted in the smallest misties at the wells. Figure 2-11 below shows the function used.



y = 4.3622x ‐ 2671.7R² = 0.999

8150

8200

8250

8300

8350

8400

2480 2490 2500 2510 2520 2530 2540

Interval Velocity (ft/sec)

Isochron (ms)

Sea Floor to E1000

Figure 2-11: Sea Floor to E1000 Velocity Function

The velocity grid derived from this function was applied to the time grid to generate a depth map shown in Figure 2-12 below which agreed with the contacts seen in the wells.

Figure 2-12: E1000 Depth structure map



2.4. Prospects

During the course of the interpretation and mapping of the Otakikpo area, a number of prospects have been identified at each of the reservoir levels. These will be summarised in the following sections together with an estimate of the hydrocarbons in place and an assessment of the exploration risk.

2.4.1. C5000 Prospects

Two areas of closure have been mapped at the C5000 level; one to the north of the Otakikpo-001 well and one south west of the Otakikpo-003 well. Figure 2-13 shows the location of these prospects.

Figure 2-13: C5000 Prospect locations

The Probability of Success (POS) for the two C5000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. C5000 Prospect 1 is located approximately 400m north west of the Otakikpo-001 well and 1.7km north west of the Otakikpo-002 well.

The Otakikpo-002 well has proven the presence of a working hydrocarbon system in the area. However, the lack of reservoir encountered in the nearer Otakikpo-001 well increases the risk for Prospect C5 1.

Prospect C5 2 is located approximately 4km south west of the Otakikpo-003 penetration point. The presence of reservoir and hydrocarbons in the Otakikpo-003 well reduce the risk for Prospect C5 2.



The parameters and overall probability of success estimated for C5000 Prospect C5 1 and Prospect C5 2 are given in Table 2-2 and Table 2-3 below:

Parameter POS Comments

Source 0.8 Source proven to south. Slight risk of oil migration shadow.

Seal 0.8 Low risk. Slight risk of cross fault leakage.

Reservoir 0.5 High risk of reservoir presence, due to absence in Otakikpo-001.

Trap 0.7 Four lines define the trap. Risk due to 2D data

Overall 0.224 22.4% Chance of Success (or approximately 1 in 4.5)

Table 2-2: C5000 Prospect C5 1 Probability of Success


Source 0.8 Source proven to in Otakikpo-003. Slight risk of oil migration shadow.


Reservoir 0.7 Reservoir present in Otakikpo-003. Reservoir presence probable.

Trap 0.6 Only two lines define trap and close to edge of data so trap may not be present as mapped.




Two prospects have been mapped at the C6000 level; Prospect C6 1 is to the north of the Otakikpo-001 well and Prospect 2 is south west of the Otakikpo-003 well. Figure 2-14 shows the location of these prospects.

The Probability of Success (POS) for the C6000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. C6000 Prospect C6 1 is mapped approximately 400m north west of the Otakikpo-001 well and 1.7km north west of the Otakikpo-002 well.

The Otakikpo-002 well has proven the presence of a working hydrocarbon system although the lack of reservoir in the nearby Otakikpo-001 well results in an increased risk for Prospect C6 1.

Prospect C6 2 is located approximately 4km south west of the Otakikpo-003 well. The presence of reservoir in the Otakikpo-003 well reduces the Reservoir risk for Prospect C6 2. However, the lack of hydrocarbons in the Otakikpo-003 well increases the Source risk.






Source 0.8 Source proven in Otakikpo-002. Slight risk of oil migration shadow.

Seal 0.6 Trap relies on two faults increasing the risk.



Overall 0.168 16.8% Chance of Success (or approximately 1 in 6)





Source 0.7 Source proven in Otakikpo-002. Absence of hydrocarbons in Otakikpo-003 increases risk.


Reservoir 0.7 Reservoir present in Otakikpo-003. Reservoir presence probable.





Two prospects have been identified at the C7000 level; Prospect C7 1 is a closure to the north of the Otakikpo-001 well and Prospect C7 2 is located south west of the Otakikpo-003 well. Figure 2-15 shows the location of these prospects.


The Probability of Success (POS) for the C7000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. C7000 Prospect C7 1 is located approximately 800m north west of the Otakikpo-001 well and 1.6km north west of the Otakikpo-002 well.



The Otakikpo-002 well has proven the presence of a working hydrocarbon system although the lack of reservoir in the nearby Otakikpo-001 well increases the overall risk for Prospect C7 1.

Prospect C7 2 is located approximately 4.2km south west of the Otakikpo-003 well. As with the C6000 prospects, the presence of reservoir sands in the Otakikpo-003 well reduces the Reservoir risk for Prospect C7 2. However, the absence of oil in the Otakikpo-003 well increases the Source risk.




Seal 0.6 Trap relies on two faults increasing the risk.






Source 0.7 Source proven to in Otakikpo-002. Absence of hydrocarbons in Otakikpo-003 increases risk.


Reservoir 0.7 Reservoir present in Otakikpo-003. Reservoir presence Probable.




2.4.4. E1000 Prospects

Three prospects have been mapped at the E1000 level; Prospect E1 2 is mapped south west of the Otakikpo-003 well. Prospect E1 3 is a closure south of the Otakikpo-003 penetration which at this level is interpreted as being north of the bounding fault. If it is shown that the Otakikpo-003 well actually penetrates the fault to the south, this prospect will become a discovery. Prospect E1 4 is located to the north of the Otakikpo-001 well.

Figure 2-15 shows the location of these prospects.



Figure 2-16: E1000 Prospect locations

The Probability of Success (POS) for the C7000 prospects was estimated using a combination of the probability of hydrocarbon charge, seal, reservoir and trap. Prospect 2 is located approximately 4.5km south west of the Otakikpo-003 well. As with the C6000 prospects, the presence of reservoir sands in the Otakikpo-003 well reduces the Reservoir risk for Prospect E1 2. The presence of oil in the Otakikpo-003 well also improves the Source risk although the fact that the Otakikpo-003 well appears to penetrate the E1000 reservoir to the north of the bounding fault does mean that some risk remains. The lack of hydrocarbons in the overlying reservoirs on the south side of the fault increases the Source risk.

Prospect 3 is located immediately south of the Otakikpo-003 well and assumes that the Otakikpo-003 well intersected the E1000 reservoir to the north of the west – east bounding fault. If this is not the case or if there is cross fault leakage the structure will no longer be classified as a prospect as the Otakikpo-003 well encountered oil at this level. It will limit the closure, however, as this well penetrated an OWC at approximately 10,729ft. The maximum closure as currently mapped is at 11,250ft so the potential STOIIP will be significantly reduced.

C7000 Prospect E1 4 is mapped approximately 1.2km north west of the Otakikpo-001 well and 2.1km north west of the Otakikpo-002 well. The Otakikpo-002 well has proven the presence of a working hydrocarbon system although the failure to encounter reservoir in the nearby Otakikpo-001 well increases the overall risk for Prospect E1 4.

The parameters and overall probability of success estimated for E1000 Prospect E1 2, Prospect E1 3 and Prospect E1 4 are given in Table 2-10, Table 2-8 and Table 2-9 below:




Source 0.7 Source proven to in Otakikpo-002. Absence of hydrocarbons in Otakikpo-003 increases risk.


Reservoir 0.7 Reservoir present in Otakikpo-003. Reservoir presence Probable.



Table 2-8: E1000 Prospect E1 2 Probability of Success


Source 0.5 No hydrocarbons in the shallower reservoirs in this location. High risk.

Seal 0.7 Risk of cross fault leakage which would reduce closure.

Reservoir 0.8 Reservoir present in Otakikpo-003 and to the north.

Trap 0.7 Four lines define trap although one line is at the edge of the structure and one is a strike line.





Seal 0.6 Risk of cross fault leakage.


Trap 0.6 Only two lines define the trap. Risk due to 2D data



Estimates of Stock Tank Oil Initially In Place(STOIIP) and Gas Initially In Place (GIIP) have been made for the discovered structures and the prospects. A summary of the input parameters and the resulting volumes is provided in Section 4.0 below.



3. Otakikpo Petrophysics Review

The Otakikpo field contains three wells that penetrate the main zones of interest. The digital data provided for all three wells comprises the standard logs required for petrophysical analysis, while additional files made available include the comprehensive set of sums and averages.

Overall the reservoir section is built up of a series of stacked channels each containing good reservoir quality sands. In total 4 zones contain hydrocarbons in both Otakikpo 002 and Otakikpo 003. However, Otakikpo 001 contains no well-developed reservoir sections, and is not included in the petrophysical analysis.

No information was available to allow a specific permeability range to be established. Lekoil supplied a table from an original Shell study showing permeability ranges (see Table 3-1 below) , but no source information. As no provenance is available for the ranges suggested, comparisons with analogue data that contains core indicate the ranges to be acceptable, and these have therefore been used for the reservoir simulation work.

Suggested permeability ranges for Otakikpo from Shell (mD)

Reservoir P85 P50 P15

C5000 545 1183 2312

C6000 729 1666 3414

C7000 512 1824 4990

E1000 449 967 1879

Table 3-1: Otakikpo area – Original permeability ranges from Shell (Source: Lekoil, July 2014)

3.1. AGR TRACS quick-look petrophysical review

No detailed petrophysical curves were supplied, thus AGR TRACS calculated a set of quick look curves to QC the overall sums and averages supplied.

The C5000 is a thin sand with a substantial shale baffle towards the middle (Figure 3-1). In Otakikpo 002 the hydrocarbon phase is predominantly gas overlying a thin oil rim, while in Otakikpo 003 the C5000 is entirely oil-bearing. Net to gross values are around 0.75 for both wells, while porosities are good at 0.22. The hydrocarbon saturations are moderate, being 0.7 for gas and 0.5 for oil.



Figure 3-1: CPI plot of C5000 reservoir in Otakikpo 002

The C6000 is a moderately thick sand with several shale baffles (Figure 3-2). As with C5000 the net to gross values are good at 0.8. The C6000 is only hydrocarbon-bearing in Otakikpo 002, while it is interpreted water-wet in Otakikpo 003. The porosities are slightly higher than seen in C5000 at around 0.25; this is possibly due to better channel development. Hydrocarbon saturations in Otakikpo 002 are excellent at 0.8.




The C7000 is a thick moderately developed sand containing multiple thin shale streaks, but where sand is present it is of good quality (Figure 3-3). Net to gross values of 0.85 are averaged over the two wells. As with C6000 only Otakikpo 002 contains hydrocarbons, but restricted to the upper part of the interval. Porosities are quite variable between the wells; with Otakikpo 002 having an average of 0.21 while Otakikpo 003 has an average of 0.27. Otakikpo 003 has the higher net to gross value of 0.9 indicating better sand development. The hydrocarbon saturations for Otakikpo 002 are good at 0.7.


The E1000 interval comprises a series of stacked channels separated by significant shale barriers (). The sequence is very thick at around 250ft, and as such the shales only have a minor impact on net to gross which is good at 0.8. The porosities are moderate, and similarly as with the C7000 Otakikpo 003 has a better porosity average at 0.23 while Otakikpo 002 has an average of 0.21. Both wells contain hydrocarbons, and both display a contact. Otakikpo 002 has a OWC 10,744ft Md while the deviated well Otakikpo 003 has a ODT at 11,659ft Md. The hydrocarbon saturations are good; averaging around 0.65, and there is a small effect of the transition zone reducing the average hydrocarbon saturation.



Figure 3-4: CPI plot of E1000 in Otakikpo 002

3.2. Otakikpo sums and averages

Comparisons between AGR TRACS quick look interpretation and the sums and averages provided by Lekoil’s petrophysical studies are good. The AGR TRACS review tends to give a slightly higher porosity, and as a consequence a slightly lower Sh by pore volume. Given the quick look nature of the AGR TRACS study, it was decided to use the supplied sums and averages for our analysis (see Table 3-2 and Table 3-3 below).



Otakikpo Wells Interval (ft Md) Reservoir Rock

Well Zones Top Bottom Gross Net Sand N/G POR_Res

002 C5000 8,243.9 8,317.88 74.0 54.50 0.74 0.217

003 C5000 8,202.6 8,321.01 118.4 65.10 0.55 0.244

002 C6000 8,381.9 8,491.88 110.0 84.50 0.77 0.233

003 C6000 8,376.6 8,470.56 93.9 74.75 0.8 0.275

002 C7000 8,683.9 8,946.88 263.0 237.00 0.9 0.214

003 C7000 8,640.7 8,845.05 204.3 163.20 0.8 0.27

002 E1000 10,557 10,787.3 230.0 186.97 0.81 0.204

003 E1000 10,626 10,883.5 257.8 184.79 0.72 0.231

Table 3-2: Otakikpo - Reservoir parameters from Shell’s petrophysical analysis

Otakikpo Wells GAS Pay OIL Pay

Well Zones Gross Pay

Net Pay N/G PORg Swg Gross

Pay Net Pay N/G PORo Swo

002 C5000 52.00 37.00 0.71 0.218 0.32 22.00 17.50 0.8 0.215 0.46

003 C5000 - - - - - 116.40 55.63 0.48 0.246 0.40

002 C6000 - - - - - 108.50 83.50 0.77 0.233 0.22

003 C6000 - - - - - - - - - -

002 C7000 - - - - - 34.00 32.50 0.96 0.206 0.30

003 C7000 - - - - - - - - - -

002 E1000 - - - - - 154.98 115.48 0.75 0.200 0.29

003 E1000 - - - - - 103.42 58.84 0.57 0.217 0.38

Table 3-3: Otakikpo – Shell’s sums and averages over oil and gas pay zones



4. In-Place Volumetric Estimates

To estimate the In-Place hydrocarbon volumes for the Otakikpo reservoirs, Gross Rock Volumes were calculated from Kingdom and input to the Monte Carlo Crystal Ball simulation. These were combined with ranges of reservoir properties resulting in a range of Stock Tank Oil Initially In Place (STOIIP) estimations. The following sections provide a summary of the inputs and results for the Otakikpo reservoirs.

4.1. Otakikpo HIIP estimates

The Otakikpo structure consists of a number of reservoirs and volumes have been estimated for each. The reservoirs identified are;

- C5000 - C6000 - C7000 - E1000

4.1.1. Otakikpo Reservoir Property inputs

Gross Rock Volumes (GRVs) were extracted from Kingdom and a range was established based on the presence or otherwise of a hydrocarbon contact and the closing contour of the structure. There is some uncertainty in the interpretation and depth conversion which has also been taken into account. However, the structures are relatively small and the difference between the Oil-Down-To (ODT) and the closing contour is small so the resulting range in GRV is quite narrow.

The reservoir properties were derived from the well data and ranges were estimated based on the limits seen in the wells. The reservoirs are generally average to good quality and because of the number of wells, the ranges are relatively narrow.

The table below (Table 4-1) lists the ranges of properties input to the Monte Carlo simulation.

Reservoir GRV (MMm3) NTG (Frac) Porosity (Frac) Sw (Frac) FVF (rb/stb)

P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10

C5000 well 002

14 28 42 0.64 0.74 0.84 0.18 0.22 0.26 0.36 0.46 0.56 1.33 1.48 1.63

C5000 Well 003

85 200 317 0.50 0.55 0.60 0.20 0.24 0.28 0.30 0.40 0.50 1.33 1.48 1.63

C6000 60 64 68 0.68 0.78 0.88 0.21 0.24 0.28 0.20 0.30 0.40 1.33 1.48 1.63

C7000 18 22 26 0.76 0.86 0.96 0.20 0.24 0.28 0.20 0.30 0.40 1.33 1.48 1.63

E1000 100 117 135 0.66 0.76 0.86 0.18 0.22 0.26 0.22 0.32 0.42 1.45 1.60 1.75

Table 4-1: Otakikpo Reservoir Property ranges (Oil)



Reservoir GRV (MMm3) NTG (Frac) Porosity (Frac) Sw (Frac) GEF (scf/ft3)

P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10

C5000 well 002

18 23 28 0.64 0.74 0.84 0.18 0.22 0.26 0.36 0.46 0.56 211 234 257

Table 4-2 Otakikpo Reservoir Property ranges (Gas)

4.1.2. C5000 Volumetric estimates

Hydrocarbons have been discovered in the C5000 reservoir in both the Otakikpo-002 and the Otakikpo-003 wells. However, in the Otakikpo-002 well, a gas cap was also encountered so the two accumulations are interpreted as being separate. Figure 4-1 shows a map of the C5000 reservoir with the various contacts illustrated.

In the Otakikpo-002 area, a Gas Oil Contact (GOC) has been identified at 8,296ft and this is used to restrict the GRV for the gas column. In the oil leg, an ODT was established at 8,320ft. This represents the minimum potential oil column and the closing contour (at 8,360ft) was used to define the upside.

Figure 4-1: C5000 Reservoir depth map with contacts

Using the input ranges provided in Table 4-1 and Table 4-2, the following hydrocarbon in place ranges were estimated (Table 4-3 and Table 4-4):



Table 4-3: C5000 STOIIP

Table 4-4: C5000 GIIP



Hydrocarbons have been discovered in the C6000 reservoir but only in the Otakikpo-002 well. Figure 4-2 shows a map of the C6000 reservoir with the various contacts illustrated.


Reservoir STOIIP (MMbls)

P90 P50 P10

C5000 002 area 5.6 9.0 14.4

C5000 003 area 31.6 55.1 93.9

TOTAL* 37.2 64.1 108.3

Reservoir GIIP (bcf)

P90 P50 P10

C5000 002 area 10.9 16.5 23.7

TOTAL* 10.9 16.5 23.7



An ODT was picked in the Otakikpo-002 well at 8,491ft and this represents the minimum case. The closing contour at 8,502ft was used to constrain the upside.

Using the input ranges provided in Table 4-1, the following hydrocarbon in place range was estimated (Table 4-5):



Hydrocarbons have been discovered in the C7000 reservoir but only in the Otakikpo-002 well. Figure 4-2 shows a map of the C7000 reservoir with the various contacts illustrated.


An Oil Water Contact (OWC) was picked in the Otakikpo-002 well at 8,718ft and this represents the maximum case. A range of GRV was established to account for uncertainty in the interpretation and the depth conversion.



P90 P50 P10

C6000 33.8 41.5 50.0




4.1.5. E1000 Volumetric estimates

Hydrocarbons have been discovered in the E1000 reservoir in both the Otakikpo-002 and the Otakikpo-003 wells. It is not entirely clear whether the two wells are in the same compartment although based on the 2D seismic data, it would appear that they are. Figure 4-4 shows a map of the C5000 reservoir with the various contacts illustrated.

Figure 4-4: E1000 Reservoir depth map with contacts

An Oil Water Contact (OWC) was picked in both the Otakikpo-002 well at 10,713ft and the Otakikpo-003 well at 10,729ft. For the purpose of this evaluation, it has been assumed that the wells have a common contact and the discrepancy is due to the deviation of the Otakikpo-003 well and the inaccuracy of the deviation survey. The deeper value has been used in order to capture the full range and this represents the maximum case.

A range of GRV was established to account for uncertainty in the interpretation and the depth conversion.



P90 P50 P10

C7000 10.2 13.2 16.8



Table 4-7: E1000 STOIIP

4.1.6. STOIIP and GIIP Summary

The following table (see Table 4-8) provides a summary of the STOIIP and GIIP estimates for the discovered reservoirs.

Table 4-8 STOIIP and GIIP Summary by reservoir


4.2. Otakikpo Prospect HIIP Estimates

A number of prospects have been identified at the various reservoir intervals and HIIP estimates have been made for each prospect at each level. Gross Rock Volumes have been estimated and the reservoir properties provided in Table 4-1 above have been used.

The following sections summarise the HIIP estimates for prospects at each reservoir level. The volumes quoted are unrisked. The Probability of Success (POS) estimates for each prospect can be found in Section 2.4 above.

4.2.1. C5000 Prospects.

Two prospects have been identified at the C5000 level. The locations are shown in Figure 2-13 in Section 2 above. GRVs for the two prospects were calculated and combined with the properties in Table 4-1 resulting in the following range of hydrocarbon in place estimates (Table 4-9).


P90 P50 P10

E1000 39.1 50.5 64.6

Reservoir STOIIP (MMbls) GIIP (bcf)

P90 P50 P10 P90 P50 P10

C5000 002 area 5.6 9.0 14.4 10.9 16.5 23.7

C5000 003 area 31.6 55.1 93.9 - - -

C6000 33.8 41.5 50.0 - - -

C7000 10.2 13.2 16.8 - - -

E1000 39.1 50.5 64.6 - - -

TOTAL* 120.3 169.3 239.7 10.9 16.5 23.7





In each case the closing contour was used to estimate the GRV and this was varied by approximately +/- 30% to provide a range to account for uncertainties in the interpretation and depth conversion.


Two prospects have been mapped at the C6000 level. The locations are shown in Figure 2-14 in Section 2 above. Using the polygons shown in Figure 2-14, GRVs for the two prospects were calculated and combined with the properties in Table 4-1. The resulting hydrocarbon in place estimates are provided in Table 4-10 below.



In both cases the closing contour was used to estimate the GRV. This was then varied by approximately +/- 30% to provide a range for input to the Monte Carlo and this accounts for uncertainties in the interpretation and depth conversion.

4.2.3. C7000 Prospect

At the C7000 reservoir level, two prospects have been identified. Their locations are shown in Figure 2-15 in Section 2 above. Polygons were drawn to constrain the areas of the prospects and these are shown in Figure 2-15. The GRVs for the two prospects were calculated and combined with the properties in Table 4-1. The resulting hydrocarbon in place estimates are shown in Table 4-11 below.


P90 P50 P10

C5000 Prospect C5 1 4.8 7.0 10.3

C5000 Prospect C5 2 1.9 2.6 3.6

TOTAL* 6.7 9.6 13.9


P90 P50 P10

C6000 Prospect C6 1 10.7 15.2 21.3

C6000 Prospect C6 2 5.4 7.9 11.8

TOTAL* 16.1 23.1 33.1





The closing contour was used in each case together with the respective polygons to estimate the GRV. This was varied by approximately +/- 30% to provide a range for input to the Monte Carlo and to account for uncertainties in the interpretation and depth conversion.

4.2.4. E1000 Prospects

Three prospects have been mapped at the E1000 reservoir level. Their locations are shown in Figure 2-16 in Section 2 above. Polygons were used to constrain the areas of the prospects and these are shown in Figure 2-16.

Prospect 3 assumes that the Otakikpo-003 well penetrates the E1000 reservoir to the north of the bounding fault. If this well actually enters the reservoir to the south, the volume of hydrocarbons in place will be significantly reduced because this well encountered an OWC well above the closing contour. For the purposes of this evaluation, it is assumed that this structure has not been sampled by the well and is therefore considered a prospect.

The GRVs for the three prospects were calculated based on the areas defined by the polygons and combined with the properties in Table 4-1. The resulting hydrocarbon in place estimates are shown in Table 4-12 below.

Table 4-12: E1000 STOIIP


The closing contour was used in each case together with the respective polygons to estimate the GRV. This was varied by approximately +/- 30% to provide a range for input to the Monte Carlo and to account for uncertainties in the interpretation and depth conversion.


P90 P50 P10

C7000 Prospect C7 1 14.3 20.8 30.4

C7000 Prospect C7 2 15.6 22.8 33.0

TOTAL* 29.9 43.6 63.4


P90 P50 P10

E1000 Prospect E1 2 4.5 6.7 9.8

E1000 Prospect E1 3 41.4 62.8 94.2

E1000 Prospect E1 4 11.5 17.0 24.7

TOTAL* 57.4 86.5 128.7



4.2.5. Summary of volumes

The following tables summarise the Prospective STOIIPs by prospect to show the volumes associated with each stacked prospect.

Table 4-13: Prospect 1 STOIIP






Prospect Reservoir STOIIP (MMbls)

P90 P50 P10

Prospect 1

C5000 4.8 7.0 10.3

C6000 10.7 15.2 21.3

C7000 14.3 20.8 30.4 TOTAL* 29.8 43.0 62.0


P90 P50 P10

Prospect 2

C5000 1.9 2.6 3.6

C6000 5.4 7.9 11.8

C7000 15.6 22.8 33.0

E1000 4.5 6.7 9.8 TOTAL* 27.4 40.0 58.2


P90 P50 P10

Prospect 3 E1000 41.4 62.8 94.2 TOTAL 41.4 62.8 94.2


P90 P50 P10

Prospect 4 E1000 11.5 17.0 24.7 TOTAL 11.5 17.0 24.7



5. OML 11 Reservoir Engineering Review

5.1. Introduction

The Otakikpo field, OML11, is located in the coastal swamp area of the eastern Niger delta, approximately 20 km west of the Opobo field. A number of 2D seismic lines were shot by Shell between 1971 and 1982 which led to the drilling of three wells and the discovery of the field. The existing wells: 001; 002 and 003, are situated across three fault blocks, with multiple hydrocarbon bearing horizons in 002 and 003. However 001, in the most northerly fault block, encountered predominately shale within the target sequence with no hydrocarbons.

Neither 002 or 003 were tested; however, log data show the sands to be of good quality. RFT samples were taken in the 003 well from the C5000 and E1000 reservoirs, confirming the presence of good quality oil.

5.2. PVT and Fluid Properties

Three RFT samples were taken in the Otakikpo 003 well: one from the shallower C5000 and two from the E1000; all confirm the presence of high API oil. Other data confirm that the reservoirs are normally pressured with a hydrostatic gradient range of between 0.414 to 0.430 psi/ft.

PVT parameters for input into the simulator were generated using correlations. Data from the 1257RFSAD sample was used, as Shell states that it was the cleaner of the two E1000 samples.

The measured sample parameters are given in Table 5-1 below.

Horizon Sample # Sample Depth

(ft MD)

Sample Depth

(ft TVDss)

Oil °API

Res. Press. (psia)

Res. Temp. (°F)

Pb (psia) Bo Rs µo

(cp@sc)

C5000 1159RFSBC 8,755 8,285 38.4 3560 157 3435 1.479 946 1.42

E1000 1257RFSAD 11,546 10,637 37.4 4575 205 4050 1.597 1148 1.24

1164RFSBC 11,546 10,637 37.4 4575 205 3680 1.597 1148 1.24

NOTE: Sample 1257RFSAD was the cleanest and therefore used in subsequent analysis

Table 5-1: Otakikpo – RFT sample parameters

5.3. Volumetrics and Properties

Using the top surface maps of the four horizons as generated from the 2D seismic, and P50 petrophysical parameters, a series of reservoir models were constructed. Small adjustments to the NTGs were applied to match the models’ in-place volumes with the P50 volumes generated from Kingdom. The basic input parameters for the models are shown in Table 5-2 below.



Horizon P50 STOIIP (MMstb)

P50 GIIP (Bscf)

NTG (frac)

Por. (frac)

Perm(mD)

Sw (frac)

Bo (rb/stb)

Gas Exp. (st ft3/ft3)

C5000 (002 area) 9 16.7 0.74 0.22 1183 0.46 - 234

C5000 (003 area) 55.1 - 0.55 0.24 1183 0.4 1.48 -

C6000 41.3 - 0.78 0.24 1666 0.3 1.48 -

C7000 13.3 - 0.86 0.24 1824 0.3 1.48 -

E1000 50.8 - 0.76 0.22 967 0.32 1.6 -

Note: kv/kh = 0.1 for all horizons

Table 5-2: Model input parameters (P50 values)

Reference depths, pressures and temperatures are also given in Table 5-3 along with the corresponding P50 contact depths. As neither of the wells had core or pressure transient data that could be used to derive permeability, values from an earlier Shell study were used. Permeabilities are very good and range from 967 to 1824mD, which is consistent with analogue fields in the Niger Delta.

Horizon Reference

Depth (ft TVDss)

Res. Press (psia)

Res. Temp. (°F)

Oil °API

Pb (psia)

Model OWC

(ft TVDss)

Model GWC

(ft TVDss)

Oil Column at 002 (003)

(ft TVD)

C5000 (002 area) - - - - - 8,320 (ODT) 8,296 53 (Gas) 44 (Oil)

C5000 (003 area) 8,285 3560 157 38.4 3468 8,385 - 182

C6000 8,430 3623 157 38.4 3468 8,497 - 114

C7000 8,700 3739 157 38.4 3468 8,718 - 34

E1000 10,637 4575 205 37.4 3798 10,729 - 172

Table 5-3: Initial pressures and contact depths

Relative permeabilities were estimated based on Corey curves and exponents. A residual oil saturation of 20%, and a critical gas saturation of 3% were assumed. The values used are given in Table 5-4 and Table 5-5, and are based on regional experience.

Horizon Initial Sw

C5000 (002 area) -

C5000 (003 area) 0.40

C6000 0.30

C7000 0.30

E1000 0.32

Table 5-4: Summary of initial Sw assumed for key reservoirs



Water-Oil

Krwo Exp Sorw Korw Exp Pc

0.3 3 0.2 1 3 0

Oil-Gas

Sorg Krog Exp Sgr Krgo Exp Pc

0.1 1 2 0.03 1 2 0

Table 5-5: Rel-perm values and end points

5.4. Model Construction

Kappa’s Rubis software was used to model the reservoirs using Voronoi grids which are generated once an external boundary, internal faulting and layering are defined. Due to the very similar top surface maps for the C horizons, a single model; which included the C5000, C6000 and C7000 reservoirs was constructed. The E1000 model was built separately as this required a substantially different top surface map and PVT properties. Figure 5-1 shows the top grid for the C5000 surface; the four wells marked were used as part of the development plan for this horizon.

Figure 5-1: Simulation grid showing top surface for the C5000 Horizon

(Note: A larger version of the depth map at top left can be found in Figure 4-1)



The seismic interpretation indicated that the sands found in the 002 and 003 wells are areally extensive and this was assumed when constructing the model. However, none of these sands appear in the Otakikpo 001 well which is some 1,000m to the north in the next fault block and contains no hydrocarbons and is predominately shale. The reason for this is unclear.

Table 5-6 below shows the layering scheme used in the model. Due to the limited data the sands are assumed to be of constant thickness within each fault block and extend to the defined boundaries at the edge of the maps. The top and bottom depth of each sand within the model agree with the well picks.

Horizon Layer No. No. of Sub-layers Description Well 002 Well 003

Top Surface 8,243 8,302

C5000 1 5 Thickness 25 68

2 1 Thickness 25 25

3 1 Thickness 25 25

Bottom 8,318 8,420

Inactive 4 1 Thickness 64 56

Top 8,382 8,377


6 1 Thickness 25 25

7 1 Thickness 25 25

Bottom 8,492 8,471

Top Surface 8,684 8,641


9 1 Thickness 40 40

10 1 Thickness 75 75

11 1 Thickness 75 75

Bottom 8,947 8,845

Top 10,557 10,626

E1000 1 2 Thickness 80 108

(Separate model)

2 2 Thickness 75 75

3 2 Thickness 75 75

Bottom 10,787 10,884

NOTE: The top of C7000 is defined by its top surface map (all depths in ft TVDss)

Table 5-6: Otakikpo - Model layer scheme



The C horizon model consists of 11 layers, which is further subdivided in the top most layer to account for the initial distribution of hydrocarbons and secondary gas cap formation.

It is know from observing nearby analogues, that fields in the Niger delta generally have very good aquifer support which leads to high recoveries. As a consequence once the models were constructed, they were run with a range of aquifer sizes for the P90, P50 and P10 cases.

In the P90 case, no additional numerical aquifer was added and the aquifer consisted only of water below the OWC in the existing grid cells and resulted in sizes that were 10-18 times that of the STOIIP. In the P50 case, a numerical aquifer was added to bring the total aquifer size to approximately 30 times that of the in-place oil, while an aquifer size of 40 times was used in the P10 case. Well numbers are assumed to be the same in each case.

5.4.1. Wells

All wells were initially modelled as vertical. Individual perforations were defined for each reservoir layer and these were adjusted on the later models to ensure sufficient stand-off from secondary gas caps. These initial wells were further optimised by use of dual completions in order to reduce the well count. The C7000 reservoir lies directly below the C6000, and therefore could be developed using dual completions in two of the C6000 wells. The E1000 reservoir is offset by some 1,500ft from the C6000, but is some 2,000ft deeper, so by using S-shaped wells it was possible to specify dual completions with two of the C6000 wells. The well scheme is summarised in Figure 5-3 overleaf. Further optimisation of the well count may be possible by using one or more dual completion wells to produce three zones, by deferring perforation of the third zone until one of the other zones is depleted. However this level of optimisation would not be appropriate at this stage of resource assessment.

Tubing pressure losses were calculated from the top of the reservoir to surface, assuming a 3.5 OD (2.75” ID) tubing. All wells were controlled on a minimum FTHP of 145 psia which was based on a 10 bar separator pressure. Maximum liquid rates of 1,500 blpd were imposed for most vertical wells. Individual perforations were shut-in once water cuts exceeded 95%.

5.4.2. Gas liberation

For any oil reservoir ultimate recovery is a function of cumulative GOR (Rp). As the size of aquifer increased from the x10-18 (P90) to x30, the level of pressure support also increased and this was observed as a reduction in the amount of liberated gas.

Figure 5-2 shows cross sections of the C6000 and C7000 reservoirs: the first image shows initial saturation conditions, while subsequent images show saturations at the end of the simulations for the P90 and P10 cases respectively. In the latter, the larger aquifer results in less liberated gas, smaller secondary gas caps and higher recoveries. As a consequence, the vertical wells are less prone to gas coning and are able to recover greater volumes before watering out.



Initial conditions in C6000 & C7000 reservoirs.

Final conditions for small aquifer (P90) case.

Final conditions for larger aquifer (P10) case

Figure 5-2: Cross-sections of C6000 and C7000 reservoirs



5.5. Forecast Scenarios

In order to determine the optimum number of wells for an Otakikpo development, the models for the C5000 (003 Area), C6000 and E1000 were run with 2, 4, 8 and 16 wells and the recoveries compared as well numbers increased. A summary of the results for E1000 are shown in Table 5-7 and Figure 5-4. As can be observed, most of the volumes are recovered by two wells with 0.5MMstb of incremental recovery at each well number doubling. Considering the cost of individual wells (~$20mln), balanced with the potential heterogeneity of the reservoirs (which is not reflected in the current models) it is likely that around four vertical wells per horizon would be prudent, although this number was refined in the final dual completion well scheme.

The P90, P50 and P10 models were run for each horizon assuming a vertical well development using the well scheme shown in Figure 5-3, and the schedule given in Table 5-8. In each case it was assumed that the 002 well would be recompleted in the E1000 and C6000, while the 003 well would be recompleted in the E1000 and C5000 horizons. The dates shown in the notional drilling schedule are the assumed dates of first production, hence drilling would start in Q4/2016 for the first new well W1 to come on stream from 01/01/2017. Each new vertical producer is assumed to take 62 days to drill and complete, while each new S-shaped producer is assumed to require 75 days for drilling and completion.

Figure 5-3: Wells and dual completion scheme

The new wells are assumed to be distributed as follows:

C5000 Southern Block: 3 new wells C6000 Central Block: 4 new wells (2 dual completions combined with

the C6000 reservoir, and 2 with the E1000 reservoir)

E1000 C5000 C6000 C7000

(003 Area)

WELL

002 X X

003 X X

W#1 X X

W#2 X X

C5 #1 X

C5 #2 X

C5 #3 X

W#3 X X

W#4 X X

'S' shaped wells

New dual completed wells ‐ W#1, W#2, W#3, W#4

VERTICAL and 'S' WELLS

Completion Locations

REVISED DUAL COMPLETION SCHEME



The E1000 Southern Block is interpreted to be in communication with the Central block (assumed common contact), thus in addition to the recompletions in the 002 and 003 wells, two new wells will be required in the central part of the accumulation which will be dual completions (E1000 and C6000). The resulting recovery factors and STOIIPs were used in a Monte Carlo analysis to derive a probabilistic range of ultimate recoveries for each horizon and field. (see Table 5-9).



OML 11 E1000 Model run from 01/01/2016 to 31/12/2039 Full Field Models k = 967mD

STOIIP (MMstb)

STOIIP/ Well

No. of wells

Prod. Mode

(NF/AL)

Oil Recovery Factor Cum Oil Recovery per Well (MMstb) Aquif. SIze

Cum Rec (MMstb)

EUR Oil RF

+1yr (2017)

+2yrs (2018)

+4yrs (2020)

+6yrs (2022)

+30yrs (2036) +1yr +2yrs +4yrs +6yrs +30yrs (6yrs) (30yrs) (30yrs)

50.5 25.3 2 wells NF THP145 0.02 0.05 0.117 0.175 0.345 0.505 1.263 2.954 4.419 8.711 x32* 8.838 17.423 0.345

12.6 4 wells NF THP145 0.057 0.111 0.223 0.318 0.358 0.720 1.401 2.815 4.015 4.520 x32* 16.059 18.079 0.358

6.3 8 wells NF THP145 0.106 0.2 0.32 0.35 0.368 0.669 1.263 2.020 2.209 2.323 x32* 17.675 18.584 0.368

3.2 16 wells NF THP145 0.206 0.31 0.362 0.374 0.385 0.650 0.978 1.143 1.180 1.215 x32* 18.887 19.443 0.385

NOTE: *Models originally run with an aquifer x 32 which resulted in recoveries of 34 to 39%. The aquifer size was reduced to between 10-18 for later runs.

Table 5-7: E1000 - Summary of models runs with sensitivities of recovery vs. well numbers

Figure 5-4: E1000 – Sensitivity of recovery vs. well numbers

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0.45

0.0 5.0 10.0 15.0 20.0 25.0 30.0

Oil Rec Fac

STOIIP/Well (MM stb)

OML11 ‐ E1000 Oil Rec Fac vs. STOIIP/Well

Oil RF (@ +30 yrs) (@ 2036) Oil RF (@ +6 yrs) (@ 2022)Oil RF (@ +4 yrs) (@ 2020) Oil RF (@ +2 yrs) (@ 2018)Oil RF (@ +1 yrs) (@ 2017)

10.0

11.0

12.0

13.0

14.0

15.0

16.0

17.0

18.0

19.0

20.0

0 5 10 15 20

Cumulative Oil at 2043 (MM stb)

No of Wells

E1000 Total Recovered Oil vs Well Number



Vertical Wells

Horizon Well Names/Number & First Production Dates

002 003 W1 W2 W3 W4 C5#1 C5#2 C5#3

E1000 01/01/15 01/02/15 01/01/17 17/03/17

C5000 003 Area 01/02/15 31/05/17 01/08/17 02/10/17

C6000 01/01/15 01/01/17 17/03/17 03/12/17 16/2/18

C7000 03/12/17 16/2/18

Table 5-8: Otakikpo – Well schedule

Monte Carlo Analysis of Otakikpo

Horizon STOIIP / GIIP Recovery Factor P50

STOIIP x P50 RF

Horizon EUR (MMstb) Probabilistic Rec. Factor

P90 P50 P10 P90 P50 P10 P90 P50 P10 P90 P50 P10

10.9 16.5 23.7

C5000 (002) 5.6 9.0 14.4 0.36 0.39 0.44 3.51 EUR C5000 (002) 2.9 3.8 4.9 0.52 0.42 0.34

C5000 (003) 31.6 55.1 93.9 0.21 0.45 0.45 24.80 C5000 (003) 15.0 21.8 30.4 0.47 0.40 0.32

C6000 33.8 41.5 50 0.26 0.31 0.36 12.87 C6000 10.0 11.5 13.2 0.30 0.28 0.26

C7000 10.2 13.2 16.8 0.36 0.39 0.44 5.15 C7000 4.6 5.3 6.1 0.45 0.40 0.36

E1000 39.1 50.5 64.6 0.27 0.32 0.43 16.16 E1000 14.4 17.3 20.8 0.37 0.34 0.32

FIELD 142.9 171.6 213.9 62.48 FIELD 49.8 57.6 66.8 0.35 0.34 0.31

NOTE: C5000 (002 Area) not explicitly simulated due to small STOIIP and thin oil leg. Recovery factors from C7000 applied. Probabilistic recovery factors calculated by EUR/STOIIP for the P90, P50 and P10 cases.

Table 5-9: Otakikpo - Monte Carlo results to determine ultimate recovery



5.5.1. Production Profiles

A comparison of the recoveries derived from the modelling is shown in Table 5-10 below:

Recovery per Well and Horizon (MMstb)

Well E1000 C5000 (003 Area) C6000 C7000 Raw Totals Adjusted

Totals*

002 4.08 3.98 8.06 7.95

003 1.37 6.73 8.09 7.98

W1 6.53 2.71 9.24 9.11

W2 4.12 2.26 6.38 6.29

C5 #1 3.08 3.08 3.04

C5 #2 8.21 8.21 8.10

C5 #3 6.86 6.86 6.76

W3 1.81 2.00 3.81 3.76

W4 2.22 2.41 4.63 4.57

EUR 16.10 24.87 12.98 4.41 58.37 57.55

STOIIP 50.8 55.1 41.3 13.3 160.50 160.50

RF 0.32 0.45 0.31 0.33 0.36 0.36

Table 5-10: Otakikpo - Recoveries for the P50 case

Note: * Represents the Raw Totals scaled in order to match the total P50 Probabilistic EUR listed in Table 5-9. The resulting profiles for the P90, P50 and P10 are shown in Figure 5-5 and Table 5-11 (overleaf). In general the development of GOR is reduced as the aquifer size increases. Peak oil rates of 17,500 to 18,400bbls/d are achieved for all cases; however in the P90 case, where the aquifer is smallest, gas rates as high as 85MMscfd result. In the P50 and P10 cases, gas rates are 47 and 32MMscfd respectively. Individual perforations are shut-in at 95% water cut which results in a maximum field water cut range from 31% to 37%.



Figure 5-5: Otakikpo – Notional production profiles for the P90-P50-P10 cases



CASE P90 P50 P10

Year Oil Rate Mbbls/d

Cum Oil MMbbls

Oil Rate Mbbls/d

Cum Oil MMbbls

Oil Rate Mbbls/d

Cum Oil MMbbls

2015 5.01 1.83 5.11 1.87 5.22 1.91

2016 5.00 3.65 5.10 3.73 5.20 3.80

2017 11.05 7.69 11.27 7.84 11.50 8.01

2018 17.22 13.98 17.69 14.30 18.04 14.60

2019 17.02 20.20 17.50 20.69 17.88 21.13

2020 16.03 26.05 16.83 26.84 17.43 27.49

2021 12.78 30.72 15.95 32.66 16.53 33.53

2022 10.70 34.62 14.73 38.04 15.49 39.19

2023 9.18 37.98 12.42 42.58 13.44 44.10

2024 7.51 40.72 10.10 46.27 11.28 48.22

2025 6.42 43.06 6.82 48.76 9.61 51.73

2026 5.16 44.95 5.68 50.83 8.21 54.73

2027 3.75 46.32 5.14 52.71 7.16 57.34

2028 1.99 47.04 4.40 54.32 6.45 59.69

2029 1.56 47.61 3.83 55.71 5.38 61.66

2030 1.36 48.11 1.76 56.36 3.55 62.96

2031 1.11 48.52 1.06 56.75 2.82 63.99

2032 0.88 48.84 0.61 56.97 2.28 64.82

2033 0.69 49.09 0.29 57.08 1.65 65.42

2034 0.51 49.28 0.28 57.18 1.33 65.90

2035 0.36 49.41 0.25 57.27 1.11 66.31

2036 0.31 49.53 0.23 57.35 0.61 66.53

2037 0.26 49.62 0.20 57.43 0.31 66.65

2038 0.21 49.70 0.18 57.49 0.21 66.72

2039 0.19 49.76 0.16 57.55 0.17 66.78

2040 0.06 49.79 0.11 57.59 0.07 66.81

Table 5-11: Otakikpo – Oil prod. profiles P90-P50-P10 cases (100%)



5.6. Results and Conclusions

A development requiring the recompletion of the two existing wells and the drilling of seven new vertical wells could achieve peak oil rates of 17,500 to 18,400bopd.

Depending on aquifer size, ultimate recoveries of 49.8 to 66.8MMstb can be achieved.

GOR development remains low in the P50 and P10 cases where the aquifers are larger, resulting in lower cumulative GORs and higher recoveries. Maximum gas rates are 47 to 32MMscfd respectively compared with 85MMscfd in the P90 case.

Recoveries of 6.36 to 8.42MMstb per well are achieved through the dual recompletions of the existing 002 & 003 wells.

Average recovery factors range from 31% in the P90 case to 42% in the P10 case where the aquifer is largest. This higher value is reasonable for Niger delta fields.

5.7. Further Studies

The current model is based on a sparse data set of 2D seismic lines and limited well data however once additional wells are drilled and further seismic is available, the potential of using horizontal wells could be studied in more detail.

Based on the performance of similar fields in the area it is likely that aquifer support will be good and therefore GORs will remain reasonably low, leading to good recoveries.

No modelling work was done on the C5000 (Area 002) reservoir in this study, this was due to the small STOIIP, thin oil leg and gas cap. This horizon could either be produced as vertical wells are recompleted from deeper layers or it could be exploited with its own dedicated horizontal well. A more detailed understanding of this reservoir would be required before any further planning could be undertaken.



6. Otakikpo Facilities Review and Cost Estimates

6.1. Introduction

The Otakikpo field in OML 11 is located near the coast in the Niger Delta about 32km east of the Bonny Island oil terminal. The access roads and well locations from the early 1980’s drilling campaign can be readily identified on satellite images (see Figure 6-1 below), which also shows the location of the processing facilities planned by Lekoil.

Figure 6-1: Location map for planned Otakikpo production facilities

(Source: Lekoil and Google Earth)



6.2. Overview of Otakikpo conceptual Central Production Facilities

The following points summarise the key facilities information and guidance provided by Lekoil mid-July 2014 (see Figure 6-2 for proposed lay-out and Figure 6-3 for the conceptual process flow diagram):

The main O&G production facilities proposed are quite simple and robust: o Two stages of separation are needed to give fully stabilized crude o Crude and produced water storage for 14 days gross production o Crude to be exported via a purpose built jetty to a nearby moored,

refurbished FSO (Floating Storage and Offloading vessel) o Local crude barges offload the FSO, on a routine basis, to a nearby oil

terminal (for onward shipping and processing) o Two years after First Oil, a 30 km crude oil export pipeline tying into a

regional oil evacuation system will be commissioned

The CPF plot plan needs to accommodate large atmospheric storage tanks (around 250,000 barrels storage capacity).

Figure 6-2: Conceptual lay-out of proposed Otakikpo CPF

(Source: Lekoil)



Figure 6-3: Conceptual process flow diagram for Otakikpo CPF

(Source: Lekoil)

The following points summarise the main high-level Facilities Engineering inputs to the current concept-level cost estimation work:

Following extensive geophysical and geotechnical site surveys of the field, the necessary land acquisition will be made for the flow lines, oil export pipeline, electric power cable route etc. rights-of-way and the Central Production Facility (CPF) site. It is intended that the well site locations, access routes and the CPF site would be sand filled.

The CPF will have initial capacity for about 18,000bpd (expandable to 35,000bpd by adding additional train at a future date). The Facility will comprise an oil inlet manifold for the hook up of the four off flow lines from the initial two off oil wells with spare slots for hook-up of future wells for the full field development. The inlet manifold will have separate headers for concurrent production and well testing purposes. The facility will be equipped with necessary process controls, protection and safeguards.

The light, sweet well stream fluids are separated into water in oil and gas. The oil/water stream will flow to the crude oil storage tanks where further separation into oil and water by gravity settling will take place. The storage tanks will have combined capacity to hold 14 days production of gross liquid. The produced water will be treated to EGASPIN specification then pumped to a produced water storage tank for temporary storage and subsequent evacuation by loading barge and transportation offshore for disposal in accordance to Nigerian regulatory guidelines.

Produced oil will be evacuated from site by barging and transported to a nearby Terminal. A shallow offshore jetty will be constructed for the mooring of, and crude offloading to, a Floating Storage and Offloading (FSO) vessel. Local crude barges will



offload the moored FSO on a regular basis. At the point of custody transfer there will be fiscal metering of barged crude oil.

The associated gas will be used for the (CPF) plant utility, plant power generation and external electrical power supply to the immediate community as part of social performance and community development initiatives. Surplus associated gas will be supplied to third party at the battery limit.

It should be noted that:

The Otakikpo well fluid is sweet with no H2S and minimal levels of CO2,

Minimal gas processing is required (basic dehydrating and dew-pointing) and

Gas compression and export pipeline facilities, as advised by Lekoil, are not included for in the current FDP concept. It was also advised that any gas compression and pipeline export requirements would be accommodated by a third party with gas being supplied from the Otakikpo CPF on an “over the fence” basis.

6.3. Otakikpo facilities cost estimates

The key assumptions were as follows:

Facilities cost estimates are to be developed for P50, P90 and P10 resource levels (as per Table 6-1).

Two existing exploration/appraisal wells are to be re-entered and completed as dual-completion wells (Otakikpo-002 and -003), with a rig mobilized in Q4/2014 such that the first recompleted well can be brought on stream very early in 2015.

3D seismic survey to be acquired in early 2016 (estimated cost $15mln). For the full field development, vertical wells are to be considered as the base-case

development scenario: o A total of 7 new-drill vertical wells to be considered; two of which will be dual

completions in the C6000 and C7000, and two of which will be S-shaped dual completions in the C6000 and E1000 (Table 6-1). First new well drilled late 2016.

o Note: wells do not require artificial lift. Storage for 250,000 barrels of gross production to be provided by on-site

atmospheric tanks, which corresponds to 14 days production at plateau rates once the full-field development is completed.

Crude to be initially exported via a nearby moored leased FSO (Floating Storage and Offloading) tanker dedicated to the field, with local crude barges offloading the FSO to nearby terminal.

Two years after First Oil, a 30 km crude oil export pipeline tying into a regional oil evacuation system will be commissioned as the main oil export facility for the field.

Gas is to be conditioned for use as fuel gas (power generation) and is assumed to be dehydrated and dew-pointed.

Gas compression is to be considered as a separate, future project (by third party). Infield crude oil pipeline and jetty transfer crude to FSO. Fiscal metering occurs

initially at barge entry point and into terminal, and later at tie-in of oil export line to regional crude evacuation system.



Vertical Wells - Otakikpo Res. Eng. Assumptions for Facils. Eng.

Description Units P90 P50 P10 Comments

STOIIP MMstb 142.9 171.6 213.9

GIIP BCF 10.9 16.5 23.7

Well No’s 7 (+2) 7 (+2) 7 (+2) 7 new wells; two with dual completions (C6000 and C7000) and 2 S-shaped dual completions in the C6000 and E1000.

Max. Field Rate blpd 18,400 19,500 19,500

bopd 17,100 17,800 18000

MMscf/d 78 48 35

Ult. Recovery MMstb 48.5 56.3 65.5 Technically recoverable volumes

Max. Liq. Rate/completion

bopd 1,500 1,500 1,500 Dual completed wells produce at up to 3,000 bopd

Max. Field Water Cut % 31% 33% 34% Individual perf’s closed in at 95%, however lower WC per well due to tubing effects.

NOTE: No artificial lift assumed. All wells controlled on FTHP, with minimum FHTP of 145psi.

Table 6-1: Res. engineering inputs for P90-P50-P10 dev. scenarios

Cost estimates were developed using Que$tor supplemented with inputs based on similar regional onshore fields’ development norms and costs following recent Facilities Engineering project work done on neighbouring blocks in that part of the Niger Delta region. Mindful of this, and of the current level of project definition and Facilities Engineering work done to date on Otakikpo, the concept-level Capex and Opex estimates reported here are assumed to have an accuracy of +/- 30%.

As noted above, cost estimates were developed for the P90-P50-P10 reservoir development scenarios assuming vertical (and two deviated wells), see Table 6-2 to Table 6-4. The cost phasings for these cases are summarised in Table 6-5. Cost efficiencies have achieved by use of dual completions in some wells, and this required S-shaped wells to be specified for the E6000/E1000 wells.

Due to the smaller aquifer assumed for the P90 case, a significantly higher gas rate is forecast than for the P50 and P10 scenarios, resulting in marginally higher overall capex for the P90 case compared to the P50 and P10 cases.



P90 Oil Case VERTICAL Wells

All costs in US$mln 1.1.2014 (100%)

TOTALS Oil Storage and

Offloading Tanker

Well Drilling (Land Rig)

Well Site

Facils.

Central Prod.

Facility

Oil & Water

Storage and

Offloading

Infield Oil Transfer Pipeline

Roads, Camps,

Buildings Description (US$mln)

Equipment 0.39 7.52 1.98 37.03 2.59 0.00 0.00 49.50

Materials 0.27 43.97 0.86 11.04 1.93 5.98 4.32 68.36

Fabrication 0.21 0.00 0.00 0.00 0.00 0.00 0.00 0.21

Prefabrication 0.00 0.00 0.21 6.43 0.71 0.00 0.00 7.34

Install. & Constr. 0.17 65.4 6.06 54.29 14.78 10.80 0.00 151.49

H. U. & Comm. 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.02

Design 0.39 1.79 0.91 12.23 2.34 1.78 0.13 19.56

Proj. Mgmt. 0.39 2.21 0.73 6.58 0.97 2.03 0.16 13.06

Insur. & Cert. 0.13 3.63 0.32 3.82 0.70 0.62 0.14 9.36

Contingency 0.29 18.68 1.38 16.43 3.00 2.65 0.7 43.14

TOTALS 2.26 143.2 12.45 147.85 27.07 23.86 5.45 362.04

Table 6-2: Overview of AGR TRACS cost estimates for P90 Case




Offloading Tanker


Well Site

Facils.

Central Prod.

Facility

Oil & Water

Storage and

Offloading


Roads, Camps,


Equipment 0.39 7.52 1.98 35.34 2.59 0.00 0.00 47.82

Materials 0.27 43.97 0.86 10.54 1.93 5.98 4.32 67.86

Fabrication 0.21 0.00 0.00 0.00 0.00 0.00 0.00 0.21

Prefabrication 0.00 0.00 0.21 6.14 0.71 0.00 0.00 7.05

Install. & Constr. 0.17 65.4 6.06 51.82 14.78 10.80 0.00 149.02

H. U. & Comm. 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.02

Design 0.39 1.79 0.91 11.68 2.34 1.78 0.13 19.01

Proj. Mgmt. 0.39 2.21 0.73 6.28 0.97 2.03 0.16 12.76

Insur. & Cert. 0.13 3.63 0.32 3.65 0.70 0.62 0.14 9.19

Contingency 0.29 18.68 1.38 15.68 3.00 2.65 0.7 42.4

TOTALS 2.26 143.2 12.45 141.13 27.02 23.86 5.45 355.34

Table 6-3: Overview of AGR TRACS cost estimates for P50 Case with vertical wells






Offloading Tanker


Well Site

Facils.

Central Prod.

Facility

Oil & Water

Storage and

Offloading


Roads, Camps,


Equipment 0.39 7.51 1.97 34.5 2.59 0.00 0.00 46.98

Materials 0.27 43.97 0.86 10.29 1.93 5.98 4.32 67.61

Fabrication 0.20 0.00 0.00 0.00 0.00 0.00 0.00 0.21

Prefabrication 0.00 0.00 0.21 5.99 0.70 0.00 0.00 6.91

Install. & Constr. 0.17 65.40 6.06 50.59 14.78 10.79 0.00 147.89

H. U. & Comm. 0.02 0.00 0.00 0.00 0.00 0.00 0.00 0.02

Design 0.39 1.72 0.91 11.40 2.34 1.78 0.13 18.73

Proj. Mgmt. 0.39 2.21 0.73 6.13 0.97 2.03 0.16 12.62

Insur. & Cert. 0.13 3.63 0.32 3.57 0.70 0.62 0.14 9.10

Contingency 0.29 18.68 1.38 15.31 3.00 2.65 0.71 42.02

TOTALS 2.26 143.19 12.44 137.77 27.00 23.85 5.46 351.98

Table 6-4: Overview of AGR TRACS cost estimates for P10 Case



Capex Cost Phasing US$mln 1.1.2014 (100%)

P90 OIL 2014 2015 2016 2017 2018 End of econ. life TOTAL

Drilling:

Tangible 17.21 1.9 22.87 19.0 0.00 60.98

Intangible 7.79 0.89 29.07 44.49 0.00 82.21

Facilities:

Facilities 4.55 40.94 96.67 47.39 0.00 189.55

Pipelines 0.00 0.00 0.00 23.85 0.00 23.85

Other Facils. 0.00 0.00 5.46 0.00 0.00 5.46

TOTAL CAPEX 362.05

Abandonment 104.21 104.21


Drilling:

Tangible 17.21 1.9 22.87 19.0 0.00 60.98

Intangible 7.79 0.89 29.07 44.49 0.00 82.21

Facilities:

Facilities 4.39 39.49 93.25 45.71 0.00 182.84

Pipelines 0.00 0.00 0.00 23.85 0.00 23.85

Other Facils. 0.00 0.00 5.46 0.00 0.00 5.46

TOTAL CAPEX 355.34



Drilling:

Tangible 17.21 1.9 22.87 19.0 0.00 60.98

Intangible 7.79 0.89 29.07 44.49 0.00 82.21

Facilities:

Facilities 4.31 38.76 91.53 44.87 0.00 179.47

Pipelines 0.00 0.00 0.00 23.85 0.00 23.85

Other Facils. 0.00 0.00 5.46 0.00 0.00 5.46

TOTAL CAPEX 351.97


Table 6-5: Overview of capex phasing for P90-P50-P10 cases



Note that the estimated abandonment costs shown in Table 6-5 are significantly greater than what is prescribed in the January 2014 Otakikpo Marginal Field farm-out agreement between NNPC/Shell/Total/Agip and Green Energy. Schedule C (p. 46) of the farm-out agreement defines a decommissioning and abandonment security to be accrued according to the formula:

Y = [0.1 D/t]*(1+r)(t-n)

Where:

Y = Amount to be paid annually into an escrow account as abandonment security

D = Development cost of field

0.1D = 10% of development cost of field

t = expected field life

r = LIBOR rate

n = particular year of production

The cumulative amount accrued over the economic field life under this formula is about 40%-45% of the total abandonment costs as estimated by AGR TRACS. The difference may therefore imply a further unfunded late-life abandonment liability.

The notional opex estimates for the four cases are summarised in Table 6-6 below:

Opex Category P90 P50 P10

Fixed Opex ($mln/yr) 20.6 20.2 20.2

Variable Opex ($/bbl) 3.0 2.73 2.60

Table 6-6: Opex assumptions for notional Otakikpo development cases



7. Economic Evaluations

7.1. Summary of Otakikpo OML 11 Marginal Field Terms

Otakikpo is held under Marginal Field Terms by Green Energy, which are a Tax & Royalty scheme with reduced tax rates. The key points are summarised below:

Capital investments eligible for Capital Allowances over 5 years (20%, 20%, 20%, 20% and 19%)

Investments eligible for Investment Tax Allowance (ITA) of 20% Petroleum Profit Tax (PPT) rate of 55% Education Tax rate of 2% of assessable profits before fiscal depreciation (deductible

for PPT purposes) Royalty on crude production (which is deductible for PPT purposes) is payable in

tranches based on production rates; as follows: Production below 5,000 bopd: 2.5% 5,001 – 10,000 bopd: 7.5% 10,001 – 15,000 bopd: 12.5% 15,001 - 25,000 bopd: 18.5%

An over-riding royalty charge of 6% (< 10,000 bopd) and 7.5% (> 10,000 bopd) is payable to the head farmors (NNPC/Shell/Total/Agip).

Losses and unutilized Capital Allowances can be carried forward indefinitely No dividend withholding tax on profits which have been subjected to PPT Contribution to Niger Delta Development Commission (NDDC) fund of 3% of the

company’s annual budget (i.e. taken to apply to both capex and opex) Cashflow available for cost recovery: 80%

AGR TRACS has audited the Lekoil economic model, and the above fiscal terms have been fully captured in the model.

7.2. Economic Assumptions

The P90-P50-P10 cases were assessed using discounted cashflow models (DCF) from 1.1.2014 based on the above fiscal terms. The PV reference date is 1.1.2014, and the NPVs are quoted on a Money Of the Day (MOD) basis. A range of discount rates (0%, 10%, 15%, and 20%) were used, with mid-year discounting.

Under the terms of the farm-in agreement, Lekoil Nigeria carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy’s share of the initial work program is reflected in Lekoil Limited’s 36% share of project NPV.

The oil price scenarios used were $80-$100-$120/bbl, escalated at 2.5%/year from 2015 onwards. Costs were similarly escalated.

Economic cut-offs were applied to all NPVs and estimates of net unrisked contingent resources. The end of economic life was defined as being reached when Opex (incl. the 3% NDDC charge) plus Royalty exceeded the gross oil production revenues.

The production profiles and the associated capex and opex cost profiles for the four cases are listed in sections 5.5 and 6.3.



7.3. Economic Evaluations

The results of the AGR TRACS economic evaluations under the 0-10-15-20% discount rates of Lekoil’s net 36% share in the Otakikpo Marginal Field (OML 11) are summarised below in Table 7-1 to Table 7-4 for the P90-P50-P10 cases. The results indicate that the P90-P50-P10 cases are economically robust at NPV(10%) under the three oil price scenarios assumed, with the farm-in terms included. Note: These NPV’s are for Lekoil Limited’s 36% interest in the project held via their 90% interest in Lekoil Nigeria.

Otakikpo Case


NPV(0%) $mln MOD PV 1.1.2014

100% Lekoil Net $80 $100 $120

P90 47.96 17.27 415.1 556.0 700.0

P50 56.75 20.43 500.8 673.3 846.7

P10 66.31 23.87 636.2 839.3 1044.6

Table 7-1: Otakikpo – Econ. results NPV(0%) for P90-P50-P10 cases net to Lekoil Limited

Otakikpo Case


NPV(10%) $mln MOD PV 1.1.2014

100% Lekoil Net $80 $100 $120

P90 47.96 17.27 199.4 279.1 360.0

P50 56.75 20.43 228.2 322.6 415.6

P10 66.31 23.87 277.8 378.6 479.4


Otakikpo Case


NPV(15%) $mln MOD PV 1.1.2014

100% Lekoil Net $80 $100 $120

P90 47.96 17.27 140.0 203.8 268.4

P50 56.75 20.43 157.2 231.8 304.3

P10 66.31 23.87 191.0 268.5 345.2


Otakikpo Case


NPV(20%) $mln MOD PV 1.1.2014

100% Lekoil Net $80 $100 $120

P90 47.96 17.27 97.6 150.5 203.7

P50 56.75 20.43 108.0 168.9 227.4

P10 66.31 23.87 132.7 194.8 255.5




8. Contingent Resource Estimates

On the basis of the economic evaluations discussed in Section 7.0 the net contingent resources attributable to Lekoil Limited have been summarised in the sections below, based on Lekoil Limited’s 90% interest in Lekoil Nigeria which in turn now holds a 40% interest in the Otakikpo Marginal Field.

8.1. Lekoil Net Contingent Resources under $80-$100-$120/bbl

Table 8-1 below summarises Lekoil’s net contingent resources for the evaluated Otakikpo P90-P50-P10 cases with vertical wells under the three oil price scenarios assumed for the economic evaluations.

Otakikpo Lekoil Limited Net Unrisked Contingent Resources MMbbls

$80 $100 $120

P90 17.27 17.35 17.35

Last Year of Production 2032 2033 2033

Otakikpo Lekoil Limited Net Unrisked Contingent Resources MMbbls

US$80/bbl US$100/bbl US$120/bbl

P50 20.43 20.51 20.51


Otakikpo Lekoil Limited Unrisked Contingent Resources MMbbls

US$80/bbl US$100/bbl US$120/bbl

P10 23.87 23.95 23.95


Table 8-1: Otakikpo – Lekoil net P90-P50-P10 Unrisked Contingent Resources



8.2. AIM Summary Tables

The tables in this section have been compiled in a manner consistent with that prescribed by the London Stock Exchange June 2009.

The volumes reported assume that Lekoil Nigeria will complete the acquisition of the planned 40% equity interest in the Otakikpo Marginal Field (OML 11) from Green Energy International Ltd, and that Lekoil Limited becomes represented in OML 11 from late 2014 onwards through its 90% interest in Lekoil Nigera. The quoted contingent resources therefore represent the economically recoverable volumes from the planned date of first production (1.1.2015) till end of economic life for the stated fields under an oil price of $80/bbl (RT).

The Chance Of Commercial Success (COCS) for the entire development of Otakikpo is currently assessed at 70%, as there is at present no agreed or approved development plan. However, as work progresses over the next few months it appears likely that some of the early drilling activity will be approved, thus the resource classifications and risk ratings will be revised in due course.



Oil & Gas – Reserves

There are currently no attributable reserves in the Otakikpo field, as the development plan has not yet been sanctioned. Work is in progress to initiate recompletion of the 002 and 003 wells late in Q4/2014, thus by that time the net attributable volumes anticipated from these two wells could be reclassified as reserves. The remainder of the future production from the later stage of the planned development will remain as Contingent Resources until the full field development plan has been approved by all partners.

Oil & Liquids: MMbbls

Gross (from 1.1.2015)


Operator

DISCOVERY 1P Proved 2P Proved & Probable

3P Proved, Probable &

Possible 1P Proved

2P Proved & Probable

3P Proved, Probable &

Possible

Otakikpo - - - - - - Green Energy

Table 8-2: AIM table of Otakikpo OML 11 Reserves; gross and net attributable to Lekoil

Note: “Operator” is the name of the company that operates the asset.

“Gross” are 100% of the reserves attributable to the licence whilst “Net Attributable” are those attributable to the AIM company. Reserves calculated under US$80/bbl.

“MMbbls” – million barrels



Oil & Gas – Contingent Resources



Risk Factor

Operator

1C Low


3C High Estimate

1C Low Estimate

2C Best Estimate

3C High Estimate

COCS (%)



Table 8-3: AIM table of Otakikpo OML 11 Contingent Resources; gross and net attributable to Lekoil

Note: “Risk Factor” for Contingent Resources means the chance, or probability, that the hydrocarbons will be commercially extracted.

“Operator” is the name of the company that operates the asset.

“Gross” are 100% of the resources attributable to the licence whilst “Net Attributable” are those attributable to the AIM company. Contingent Resources calculated under US$80/bbl.




Risked Contingent Resources Net to Lekoil (from 1.1.2015):

Oil MMbbls


Risk Factor


1C Low


3C High Estimate

COCS (%)

1C Low Estimate

2C Best Estimate

3C High Estimate


Otakikpo 17.27 20.43 23.87 70% 12.09 14.30 16.71

Table 8-4: AIM table of Otakikpo OML 11 Contingent Resources net attributable to Lekoil; unrisked and risked

Note: “Risk Factor” for Contingent Resources means the chance, or probability, that the hydrocarbons will be commercially extracted.

Contingent Resources calculated under US$80/bbl.



Oil – Prospective Resources

STOIIP ranges have been estimated for four undrilled prospects as part of this review (see section 4.2.5), but due to lack of engineering and cost data for notional developments no estimates of recoverable volumes and no economic assessments have been carried out for these prospects.

Oil & Liquids: MMbbls Gross (on-block) Net Attributable to Lekoil Limited

(40% of Gross on-block resources) Operator

PROSPECTIVE RESOURCES (Technical Resources)

Low Mid High Low Mid High

Prospect 1

Prospect 2

Prospect 3

Prospect 4

Table 8-5: AIM table of Otakikpo OML 11 Unrisked Prospective Resources; gross and net attributable to Lekoil

Note: No risk factors estimated due to lack of technical data




9. Conclusions

AGR TRACS has carried out a full review of the Otakikpo Marginal Field based on data provided by Lekoil and independent development cost estimates for a notional development scheme according to an outline provided by Lekoil in mid-July 2014.

There is no approved development plan at present, hence the volumes assumed to be recovered through the initial recompletions and the subsequent development scheme have been classified as Contingent Resources with a Chance Of Commercial Success (COCS) of 70%. The Contingent Resource estimates have been derived using an economic model provided by Lekoil and reviewed by AGR TRACS. This is considered to correctly represent the Marginal Field Terms applicable to Otakikpo.

The net attributable volumes quoted in this report reflect the farm-in terms agreed with Green Energy in May 2014 in order to transfer a 40% equity interest in the Otakikpo Marginal Field in OML 11 to Lekoil Oil and Gas, with 90% of this interest attributable to Lekoil Limited. The completion of the transfer requires a formal approval from the Minister of Petroleum Resources. However, Lekoil Oil and Gas and Green Energy have executed a Financial and Technical Services Agreement (FTSA) whereby Lekoil Oil and Gas is entitled to a 40% economic interest in the Otakikpo Marginal Field. Under the terms of the farm-in agreement, Lekoil Oil and Gas will carry Green Energy for the initial work program costs of approximately $80 million including $13.36 million contingency. The cost carry of Green Energy’s share of the initial work program is reflected in Lekoil’s share of project NPV. Following the review, AGR TRACS can report that the net unrisked 1C-2C-3C (P90-P50-P10) Contingent Resources at $80/bbl attributable to Lekoil (effective from late 2014) are estimated to be 17.27-20.43-23.87 MMbbls. The corresponding net risked 1C-2C-3C (P90-P50-P10) contingent resources at $80/bbl attributable to Lekoil are estimated at 12.09-14.30-16.71 MMbbls oil, see Table 9-1 below.


Oil MMbbls


Risk Factor


1C Low


3C High Estimate

COCS (%)

1C Low Estimate

2C Best Estimate

3C High Estimate


Otakikpo 17.27 20.43 23.87 70% 12.09 14.30 16.71

Table 9-1: Otakikpo OML 11 Unrisked and Risked Contingent Resources net attributable to Lekoil

Economic evaluations have been carried out under $80-$100-$120/bbl oil price scenarios for the P90-P50-P10 cases with deviated wells from 1.1.2015 until end of economic life.

The NPV(10%) MOD results of the economic evaluations indicate that the planned development of the Otakikpo Marginal Field is a robust project under all three oil price scenarios - see Table 9-2 for the NPV(10%) results (with the farm-in terms included).



Otakikpo Case


NPV(10%) $mln MOD PV 1.1.2014

100% Lekoil Net $80 $100 $120

P90 47.96 17.27 199.4 279.1 360.0

P50 56.75 20.43 228.2 322.6 415.6

P10 66.31 23.87 277.8 378.6 479.4

Table 9-2: Otakikpo P90-P50-P10 cases - Economic results NPV(10%), unrisked net to Lekoil Limited



10. APPENDIX 1 - Petroleum Resources Classification

Summary of 2007 SPE Petroleum Resources Classification

The following paragraphs are quoted from the 2007 SPE PRMS Guidance Notes and summarise the key resources categories, while Fig. A-1 shows the recommended resources classification framework.

Class/Sub-class Definition

Reserves Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.

On Production The development project is currently producing and selling petroleum to market.

Approved for Development All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way.

Justified for Development

Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

Contingent Resources

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Development Pending

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

Development Unclarified or on Hold

A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.

Development Not Viable

A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.

Prospective Resources Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.

Prospect A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.



Fig. A-1: 2007 SPE PRMS Petroleum Resources Classification Framework



11. APPENDIX 2 - Glossary

$ US Dollars

% percent

°C Degrees Celcius

2D Two Dimensional

3D Three Dimensional

API American Petroleum Institute

AVO Amplitude Variation with Offset

Av Phi Average Porosity (from log evaluation)

Av Sw Average water Saturation (from log evaluation)

bbls Barrels

Bscf Billion standard cubic feet of natural gas

bfpd Barrels of fluid per day

boe barrels of oil equivalent

boepd barrels of oil equivalent per day

bopd barrels oil per day

bpd barrels per day

bwpd barrels of water per day

Cali Caliper

Capex capital expenditure

CGR Condensate Gas Ratio

cm3 cubic centimetre

m3 cubic metre

COCS Chance of Commercial Success

CPI Computer Processed Interpretation (of logs)

CT Corporation Tax

Den Density log

D res Deep resistivity log (deep investigation)

DST Drill Stem Test

DT Sonic log

E & A Exploration & Appraisal

ft feet

FTHP Flowing Tubing Head Pressure

FWL Free Water Level

G & G Geological and Geophysical

Gas sat Gas saturation

GDT Gas Down To

GIIP Gas Initially In Place

GOR Gas to Oil Ratio

GR Gamma Ray log

GRV Gross Rock Volume

GUT Gas Up To

GWC Gas Water Contact

HCDT Hydro‐Carbon Down To

HCWC Hydro‐Carbon Water Contact

IRR Internal Rate of Return (from MOD cashflows)

JV Joint Venture

K Permeability

km Kilometre

km2 Square kilometres

LIBOR London Interbank Offered Rate

m metre

Mbbls thousand barrels of oil (unless otherwise

stated)

Mboe thousand barrels of oil equivalent

Mbopd thousand barrels of oil per day

Mcf thousand cubic feet

Mcfd thousand cubic feet per day of natural gas

MD Measured Depth

mD milli Darcies

MM million

MMbbls million barrels of oil

MMstb million stock‐tank barrels of oil

MMbo million barrels of oil

MMboe million barrels of oil equivalent

MMcf million cubic feet of natural gas

MMscfd million cubic feet of natural gas per day

MOD Money Of the Day

N/G Net to Gross

Neu Neutron log

NFA No Further Activity

NPV Net Present Value



OBC Ocean Bottom Cable

ODT Oil Down To

OML Oil Mining Licence

Opex operating expenditure

OPL Oil Prospecting Lease

OUT Oil Up To

OWC Oil Water Contact

P & A Plugged and Abandoned

p.a. per annum

P10 10% probability of being exceeded



POS Possibility Of Success

ppm wt Parts per million by weight

PRMS Petroleum Resource Management System

PSC Production Sharing Contract

psi pounds per square inch

psia pounds per square inch absolute

PV Present Value

PVT Pressure Volume Temperature

RF Recovery Factor

RFT Repeat Formation Tester

RROR Real Rate of Return (from RT cashflows)

RT Real Terms

SG Specific Gravity

SMT Kingdom a PC‐based interpretation workstation

SPE Society of Petroleum EnginHawkleys

sq km square kilometres

S res Short resistivity log (shallow investigation)

ss subsea

STOIIP Stock Tank Oil Initially In Place

Sw water Saturation

Swavg average water Saturation

Sxo water Saturation in invaded zone

TD Total Depth

tvd true vertical depth

tvdss true vertical depth subsea

tvt true vertical thickness

TWT Two‐Way Time

WI Working Interest

AGR TRACS Competent Person's Report on Otakikpo Marginal Field, OML 11, Nigeria, for Lekoil

Documents